**UNITED STATESSECURITIES AND EXCHANGE COMMISSION**

**Washington,D.C. 20549**

**FORM 10-Q**

**x**                              QUARTERLYREPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACTOF 1934

**Forthe quarterly period ended June 30, 2007**

**OR**

**o**                                 TRANSITIONREPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGEACT OF 1934

**Forthe transition period from                  to                  **

**Commissionfile number 1-10934**

**ENBRIDGE ENERGY PARTNERS, L.P.**

(Exact name of registrantas specified in its charter)

| **Delaware**                                                     |   | **39-1715850**                        |
|------------------------------------------------------------------|--------|---------------------------------------|
| (State or other  jurisdiction of  incorporation or organization) |   | (I.R.S. Employer  Identification No.) |

 

1100 LouisianaSuite 3300Houston, TX 77002

(Address of principalexecutive offices and zip code)

**(713) 821-2000**

(Registrant’s telephonenumber, including area code)

Indicate by check mark whether the registrant:(1) has filed all reports required to be filed by Section 13 or15(d) of the Securities Exchange Act of 1934 during the preceding 12 months(or for such shorter period that the registrant was required to file suchreports), and (2) has been subject to such filing requirements for thepast 90 days. Yes x  No o

Indicate by check mark whether the registrant is alarge accelerated filer, an accelerated filer, or a non-accelerated filer(as defined in Rule 12b-2 of the Exchange Act). Large AcceleratedFiler x AcceleratedFiler o Non-Accelerated Filer o

Indicate by check mark whether the registrant is ashell company (as defined in Rule 12b-2 of the Exchange Act).Yes o  No x

**The Registrant had 55,238,834Class A common units outstanding as of July 30, 2007.**

 

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**ENBRIDGE ENERGYPARTNERS, L.P.**

**TABLEOF CONTENTS**

|                                |   | **PART I. FINANCIAL INFORMATION**                                                                                 |   |   |
|--------------------------------|--------|------------------------------------------------------------------------------------------------------------------------|--------|--------|
| Item 1.                        |   | Financial Statements                                                                                                   |   |   |
|                           |   | Consolidated Statements of Income for the  three and six month periods ended June 30, 2007 and 2006               |   | 3      |
|                           |   | Consolidated Statements of Comprehensive  Income for the three and six month periods ended June 30, 2007 and 2006 |   | 4      |
|                           |   | Consolidated Statements of Cash Flows  for the six month periods ended June 30, 2007 and 2006                |   | 5      |
|                           |   | Consolidated Statements of Financial  Position as of June 30, 2007 and December 31, 2006                |   | 6      |
|                           |   | Notes  to Consolidated Financial Statements                                                                            |   | 7      |
| Item  2.                       |   | Management’s Discussion and  Analysis of Financial Condition and Results of Operations                            |   | 17     |
| Item  3.                       |   | Quantitative and Qualitative  Disclosures About Market Risk                                                            |   | 39     |
| Item  4.                       |   | Controls and Procedures                                                                                                |   | 41     |
| **PART II. OTHER INFORMATION** |
| Item 1.                        |   | Legal Proceedings                                                                                                      |   | 42     |
| Item 1A.                       |   | Risk Factors                                                                                                           |   | 42     |
| Item 6.                        |   | Exhibits                                                                                                               |   | 45     |
| **Signatures**                 |   | 46                                                                                                                     |
| **Exhibits**                   |   |                                                                                                                   |
|                                |        |                                                                                                                        |        |        |  |  |

 

*In this report, unless the context requiresotherwise, references to “we”, “us”, “our”, or the “Partnership” are intendedto mean Enbridge Energy Partners, L.P. and its consolidated subsidiaries. ThisQuarterly Report on Form 10-Q contains forward-looking statements. Theseforward-looking statements are identified as any statement that does not relatestrictly to historical or current facts. They use words such as “anticipate,”“believe,” “continue,” “estimate,” “expect,” “forecast,” “intend,” “may,”“plan,” “position,” “projection,” “strategy,” “could,” “would,” or “will” orthe negative of those terms or other variations of them or by comparableterminology. In particular, statements, expressed or implied, concerning futureactions, conditions or events or future operating results or the ability togenerate sales, income or cash flow or to make distributions are forward-lookingstatements. Forward-looking statements are not guarantees of performance. Theyinvolve risks, uncertainties and assumptions. Future actions, conditions orevents and future results of operations may differ materially from thoseexpressed in these forward-looking statements. Many of the factors that willdetermine these results are beyond our ability to control or predict. Foradditional discussion of risks, uncertainties and assumptions, see “RiskFactors” included in Part I, Item 1A of our Annual Report on Form 10-K for thefiscal year ended December 31, 2006 and in Part II, Item 1A of our quarterlyreports on Form 10-Q.*

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**PART I—FINANCIALINFORMATION**

**Item1.**                        FinancialStatements

**ENBRIDGE ENERGYPARTNERS, L.P.**

**CONSOLIDATED STATEMENTS OF INCOME**

| ** **                                                             | ** ** | **Three months ended  June 30,**                                     | ** ** | **Six months ended   June 30,** | ** ** |
|------------------------------------------------------------------------|------------|-------------------------------------------------------------------------------------|------------|-----------------------------------------------------|------------|
| ** **                                                             | ** ** | **2007**                                                                            | ** ** | **2006**                                            | ** ** | **2007** | ** ** | **2006** | ** ** |
| ** **                                                             | ** ** | **(unaudited; in millions, except per unit amounts)** | ** ** |
| Operating revenue                                                      |       | $                                                                                   | 1,738.7    |                                                | $          | 1,424.7 |   | $ | 3,451.4 |   | $ | 3,313.3 |   |
| Operating  expenses                                                    |       |                                                                                |       |                                                |       |   |   |   |   |
| Cost of natural gas (Note 10)                                          |       | 1,475.6                                                                             |       | 1,185.6                                             |       | 2,959.9 |   | 2,833.3 |   |
| Operating and administrative                                           |       | 105.1                                                                               |       | 87.3                                                |       | 202.8 |   | 161.2 |   |
| Power                                                                  |       | 27.3                                                                                |       | 24.2                                                |       | 57.4 |   | 50.5 |   |
| Depreciation and amortization                                          |       | 39.8                                                                                |       | 34.0                                                |       | 76.3 |   | 66.7 |   |
|                                                                   |       | 1,647.8                                                                             |       | 1,331.1                                             |       | 3,296.4 |   | 3,111.7 |   |
| Operating income                                                       |       | 90.9                                                                                |       | 93.6                                                |       | 155.0 |   | 201.6 |   |
| Interest expense                                                       |       | 21.5                                                                                |       | 27.6                                                |       | 46.8 |   | 55.5 |   |
| Other income                                                           |       | 0.5                                                                                 |       | 4.4                                                 |       | 1.9 |   | 5.4 |   |
| Income before  income tax expense                                      |       | 69.9                                                                                |       | 70.4                                                |       | 110.1 |   | 151.5 |   |
| Income tax  expense (Note 6)                                           |       | 1.3                                                                                 |       | —                                              |       | 2.4 |   | — |   |
| Net income                                                             |       | $                                                                                   | 68.6       |                                                | $          | 70.4 |   | $ | 107.7 |   | $ | 151.5 |   |
| Net income allocable to limited partner units (Note  2)                |       | $                                                                                   | 59.3       |                                                | $          | 63.2 |   | $ | 90.7 |   | $ | 137.1 |   |
| Net income per limited partner unit (basic and  diluted) (Note 2) |       | $                                                                                   | 0.69       |                                                | $          | 0.96 |   | $ | 1.10 |   | $ | 2.08 |   |
| Weighted average  limited partner units outstanding                    |       | 86.5                                                                                |       | 65.9                                                |       | 82.2 |   | 65.8 |   |

 

The accompanying notes are an integral part of these consolidated financial statements.

3

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**ENBRIDGE ENERGYPARTNERS, L.P.**

**CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME**

| ** **                                   | ** ** | **Three months ended  June 30,** | ** ** | **Six months ended  June 30,** | ** ** |
|----------------------------------------------|------------|-------------------------------------------------|------------|-----------------------------------------------|------------|
| ** **                                   | ** ** | **   2007   **    | ** ** | **   2006   **  | ** ** | **2007** | ** ** | **2006** | ** ** |
| ** **                                   | ** ** | **(unaudited; in millions)**          | ** ** |
| Net income                                   |       |                                            | $          | 68.6                                          |       |   |   | $ | 70.4 |   |   | $ | 107.7 |   | $ | 151.5 |   |
| Other  comprehensive income (loss) (Note 10) |       |                                            | 5.3        |                                          |       |   | (30.3 | ) |   | (35.0 | ) | 3.8 |   |
| Comprehensive income                         |       |                                            | $          | 73.9                                          |       |   |   | $ | 40.1 |   |   | $ | 72.7 |   | $ | 155.3 |   |

 

The accompanying notes are an integral part of these consolidated financial statements.

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**ENBRIDGE ENERGYPARTNERS, L.P.**

**CONSOLIDATED STATEMENTS OF CASH FLOWS**

| ** **                                                                         | ** ** | **Six months ended  June 30,** | ** ** |
|------------------------------------------------------------------------------------|------------|-----------------------------------------------|------------|
| ** **                                                                         | ** ** | **2007**                                      | ** ** | **2006** | ** ** |
| ** **                                                                         | ** ** | **(unaudited;   in millions)**      | ** ** |
| Cash provided by operating activities                                              |       |                                          |       |   |   |
| Net income                                                                         |       | $                                             | 107.7      |   | $ | 151.5 |   |
| Adjustments to reconcile net income to net cash  provided by operating activities: |       |                                          |       |   |   |
| Depreciation and  amortization                                                     |       | 76.3                                          |       | 66.7 |   |
| Derivative fair value  (gains) losses (Note 10)                                    |       | 12.6                                          |       | (29.4 | ) |
| Gain on Sale of Assets                                                             |       | (0.2                                          | )          | — |   |
| Inventory market price  adjustment                                                 |       | 1.5                                           |       | 9.7 |   |
| Environmental  liabilities (Note 9)                                                |       | (1.0                                          | )          | 0.8 |   |
| Other                                                                              |       | (1.8                                          | )          | 1.0 |   |
| Changes in operating assets and liabilities, net of  cash acquired:                |       |                                          |       |   |   |
| Receivables, trade and  other                                                      |       | 49.4                                          |       | (33.1 | ) |
| Due from General Partner  and affiliates                                           |       | 5.0                                           |       | 14.2 |   |
| Accrued receivables                                                                |       | 43.5                                          |       | 239.6 |   |
| Inventory (Note 4)                                                                 |       | (3.9                                          | )          | (26.5 | ) |
| Current and long-term  other assets (Note 10)                                      |       | (4.5                                          | )          | (4.3 | ) |
| Due to General Partner  and affiliates                                             |       | 19.7                                          |       | 11.0 |   |
| Accounts payable and  other (Notes 3 and 10)                                       |       | (14.5                                         | )          | (7.4 | ) |
| Accrued purchases                                                                  |       | (42.4                                         | )          | (221.7 | ) |
| Interest payable                                                                   |       | 5.3                                           |       | — |   |
| Current income tax  payable (Note 6)                                               |       | 2.3                                           |       | — |   |
| Property and other taxes  payable                                                  |       | 3.7                                           |       | (5.1 | ) |
| Net cash provided by  operating activities                                         |       | 258.7                                         |       | 167.0 |   |
| Cash used in investing activities                                                  |       |                                          |       |   |   |
| Additions to property,  plant and equipment                                        |       | (891.5                                        | )          | (285.2 | ) |
| Changes in construction  payables                                                  |       | 87.2                                          |       | 4.8 |   |
| Asset acquisitions, net  of cash acquired                                          |       | —                                        |       | (33.2 | ) |
| Proceeds from Sales of  Assets                                                     |       | 0.9                                           |       | — |   |
| Other                                                                              |       | (2.0                                          | )          | 0.1 |   |
| Net cash used in  investing activities                                             |       | (805.4                                        | )          | (313.5 | ) |
| Cash provided by financing activities                                              |       |                                          |       |   |   |
| Net proceeds from unit  issuances (Note 8)                                         |       | 628.8                                         |       | — |   |
| Distributions to  partners (Note 8)                                                |       | (115.8                                        | )          | (113.2 | ) |
| Net borrowings from  Credit Facility (Note 7)                                      |       | —                                        |       | 10.0 |   |
| Net issuances  (repayments) of commercial paper (Note 7)                           |       | (46.5                                         | )          | 269.1 |   |
| Repayment on affiliate  loan                                                       |       | —                                        |       | (20.0 | ) |
| Net cash provided by  financing activities                                         |       | 466.5                                         |       | 145.9 |   |
| Net decrease in cash and  cash equivalents                                         |       | (80.2                                         | )          | (0.6 | ) |
| Cash and cash  equivalents at beginning of year                                    |       | 184.6                                         |       | 89.8 |   |
| Cash and cash equivalents at end of period                                         |       | $                                             | 104.4      |   | $ | 89.2 |   |

 

The accompanying notes are an integral part of these consolidated financial statements.

5

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**ENBRIDGE ENERGYPARTNERS, L.P.**

**CONSOLIDATED STATEMENTS OF FINANCIAL POSITION**

| ** **                                                                                                   | ** ** | **June 30,**                                     | ** ** | **December 31,** | ** ** |
|--------------------------------------------------------------------------------------------------------------|------------|-------------------------------------------------------|------------|-----------------------|------------|
| ** **                                                                                                   | ** ** | **2007**                                              | ** ** | **2006**              | ** ** |
| ** **                                                                                                   | ** ** | **(unaudited;   dollars in millions)** | ** ** |
| **ASSETS**                                                                                                   |       |                                                  |       |                  |       |   |   |
| Current assets                                                                                               |       |                                                  |       |                  |       |   |   |
| Cash and cash  equivalents (Note 3)                                                                          |       | $                                                     | 104.4      |                  |       | $ | 184.6 |   |   |
| Receivables, trade and  other, net of allowance for doubtful accounts of $1.7 in 2007 and $2.4  in 2006 |       | 97.2                                                  |       |                  | 146.7      |   |   |
| Due from General Partner  and affiliates                                                                     |       | 25.5                                                  |       |                  | 30.5       |   |   |
| Accrued receivables                                                                                          |       | 473.0                                                 |       |                  | 516.5      |   |   |
| Inventory (Note 4)                                                                                           |       | 119.5                                                 |       |                  | 117.1      |   |   |
| Other current assets  (Note 10)                                                                              |       | 15.8                                                  |       |                  | 13.9       |   |   |
|                                                                                                         |       | 835.4                                                 |       |                  | 1,009.3    |   |   |
| Property, plant and  equipment, net (Note 5)                                                                 |       | 4,641.9                                               |       |                  | 3,824.9    |   |   |
| Other assets, net (Notes  6 and 10)                                                                          |       | 36.2                                                  |       |                  | 26.1       |   |   |
| Goodwill                                                                                                     |       | 265.7                                                 |       |                  | 265.7      |   |   |
| Intangibles, net                                                                                             |       | 97.3                                                  |       |                  | 97.8       |   |   |
|                                                                                                         |       | $                                                     | 5,876.5    |                  |       | $ | 5,223.8 |   |   |
| **LIABILITIES  AND PARTNERS’ CAPITAL**                                                                  |       |                                                  |       |                  |       |   |   |
| Current liabilities                                                                                          |       |                                                  |       |                  |       |   |   |
| Due to General Partner  and affiliates                                                                       |       | $                                                     | 42.3       |                  |       | $ | 22.6 |   |   |
| Accounts payable and  other (Notes 3 and 10)                                                                 |       | 314.0                                                 |       |                  | 211.5      |   |   |
| Accrued purchases                                                                                            |       | 487.9                                                 |       |                  | 530.3      |   |   |
| Interest payable                                                                                             |       | 12.1                                                  |       |                  | 11.4       |   |   |
| Property and other taxes  payable (Note 6)                                                                   |       | 23.8                                                  |       |                  | 18.6       |   |   |
| Loans from General  Partner and affiliates                                                                   |       | 140.8                                                 |       |                  | 136.2      |   |   |
| Current maturities of  long-term debt                                                                        |       | 31.0                                                  |       |                  | 31.0       |   |   |
|                                                                                                         |       | 1,051.9                                               |       |                  | 961.6      |   |   |
| Long-term debt  (Note 7)                                                                                     |       | 2,015.8                                               |       |                  | 2,066.1    |   |   |
| Environmental  liabilities (Note 9)                                                                     |       | 3.7                                                   |       |                  | 3.3        |   |   |
| Other long-term  liabilities (Note 10)                                                                       |       | 176.0                                                 |       |                  | 149.4      |   |   |
|                                                                                                         |       | 3,247.4                                               |       |                  | 3,180.4    |   |   |
| Commitments and contingencies (Note 9)                                                                  |       |                                                  |       |                  |       |   |   |
| Partners’ capital (Note 8)                                                                              |       |                                                  |       |                  |       |   |   |
| Class A common  units (Units issued—55,238,834 in 2007 and 49,938,834 in 2006)           |       | 1,370.2                                               |       |                  | 1,141.7    |   |   |
| Class B common  units (Units issued—3,912,750 in 2007 and 2006)                                    |       | 74.9                                                  |       |                  | 67.6       |   |   |
| Class C units  (Units issued—17,459,447 in 2007 and 11,070,152 in 2006)                            |       | 850.2                                                 |       |                  | 509.8      |   |   |
| i-units (Units  issued—13,108,074 in 2007 and 12,674,148 in 2006)                                       |       | 497.5                                                 |       |                  | 466.3      |   |   |
| General Partner                                                                                              |       | 60.9                                                  |       |                  | 47.6       |   |   |
| Accumulated other  comprehensive loss (Note 10)                                                              |       | (224.6                                                | )          |                  | (189.6     | ) |   |
|                                                                                                         |       | 2,629.1                                               |       |                  | 2,043.4    |   |   |
|                                                                                                         |       | $                                                     | 5,876.5    |                  |       | $ | 5,223.8 |   |   |

 

The accompanying notes are an integral part of these consolidated financial statements.

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**ENBRIDGE ENERGYPARTNERS, L.P.NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS(unaudited)**

**1.**                 BASISOF PRESENTATION

We have prepared the accompanying unaudited interimconsolidated financial statements in accordance with accounting principlesgenerally accepted in the United States of America for interim consolidatedfinancial information and with the instructions to Form 10-Q and Rule 10-01of Regulation S-X. Accordingly, they do not include all theinformation and footnotes required by accounting principles generally acceptedin the United States of America for complete consolidated financial statements.In the opinion of management, they contain all adjustments, consisting only ofnormal recurring adjustments, which management considers necessary to presentfairly our financial position at June 30, 2007 and December 31, 2006;our results of operations and comprehensive income for the three and six monthperiods ended June 30, 2007 and 2006; and our cash flows for the six monthperiods ended June 30, 2007 and 2006. We derived the ConsolidatedStatement of Financial Position as of December 31, 2006, from the auditedfinancial statements included in our 2006 Annual Report on Form 10-K.

The results of operationsfor the three and six month periods ended June 30, 2007, should not betaken as indicative of the results to be expected for the full year due toseasonality of portions of the natural gas business, timing and completion ofour construction projects, maintenance activities and the impact of forwardnatural gas prices and differentials on certain derivative financialinstruments that are accounted for using mark-to-market accounting.Our consolidated statements of cash flows for the period ended June 30,2006 include reclassifications that were made to present changes inenvironmental liabilities separately from changes in Accounts payable andother, consistent with our current period presentation. Additionally, wereclassified $6.4 million from “Other assets, net” to “Intangibles, net” in ourDecember 31, 2006 consolidated statement of financial position related torights we received for contributions we made in aid of construction projects,consistent with our current period presentation. These reclassifications haveno effect on previously reported results of operations, comprehensive income orpartners’ capital. Our interim consolidated financial statements should be readin conjunction with our consolidated financial statements and notes theretopresented in our Annual Report on Form 10-K for the fiscal yearended December 31, 2006.

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**2.**                 NETINCOME PER LIMITED PARTNER UNIT

Netincome per limited partner unit is computed by dividing net income, afterdeduction of Enbridge Energy Company, Inc.’s (the “General Partner”)allocation, by the weighted average number of our limited partner unitsoutstanding. The General Partner’s allocation is equal to an amount based uponits general partner interest, adjusted to reflect an amount equal to itsincentive distributions and an amount required to reflect depreciation on theGeneral Partner’s historical cost basis for assets contributed on formation ofthe Partnership. We have no dilutive securities. Net income per limited partnerunit was determined as follows:

| ** **                                               | ** ** | **Three months  ended June 30,**                     | ** ** | **Six months   ended June 30,** | ** ** |
|----------------------------------------------------------|------------|---------------------------------------------------------------------|------------|-----------------------------------------------------|------------|
| ** **                                               | ** ** | **2007**                                                            | ** ** | **2006**                                            | ** ** | **2007** | ** ** | **2006** | ** ** |
| ** **                                               | ** ** | **(in millions, except per unit amounts)** | ** ** |
| Net income                                               |       | $                                                                   | 68.6       |                                                | $          | 70.4 |   | $ | 107.7 |   | $ | 151.5 |   |
| Allocations to the General Partner:                      |       |                                                                |       |                                                |       |   |   |   |   |
| Net income allocated to the General Partner              |       | (1.4                                                                | )          | (1.4                                                | )          | (2.2 | ) | (3.0 | ) |
| Incentive income allocated to the General Partner        |       | (7.9                                                                | )          | (5.7                                                | )          | (14.7 | ) | (11.3 | ) |
| Historical cost depreciation adjustments                 |       | —                                                              |       | (0.1                                                | )          | (0.1 | ) | (0.1 | ) |
|                                                     |       | (9.3                                                                | )          | (7.2                                                | )          | (17.0 | ) | (14.4 | ) |
| Net income allocable to limited partner units            |       | $                                                                   | 59.3       |                                                | $          | 63.2 |   | $ | 90.7 |   | $ | 137.1 |   |
| Weighted average limited partner units outstanding       |       | 86.5                                                                |       | 65.9                                                |       | 82.2 |   | 65.8 |   |
| Net income per  limited partner unit (basic and diluted) |       | $                                                                   | 0.69       |                                                | $          | 0.96 |   | $ | 1.10 |   | $ | 2.08 |   |

 

**3.**                 CASHAND CASH EQUIVALENTS

We extinguish liabilitieswhen a creditor has relieved us of our obligation, which occurs when ourfinancial institution honors a check that the creditor has presented forpayment. Accordingly, obligations for which we have issued check payments thathave not yet been presented to the financial institution of approximately $31.8million at June 30, 2007 and $46.9 million at December 31, 2006,are included in Accounts payable and other on the Consolidated Statements ofFinancial Position.

**4.**                 INVENTORY

Inventoryis comprised of the following:

| ** **                                     | ** ** | **June 30,  2007** | ** ** | **December  31,  2006** | ** ** |
|------------------------------------------------|------------|-------------------------|------------|-----------------------------------|------------|
| ** **                                     | ** ** | **(in millions)**  | ** ** |
| Material and  supplies                         |       |                    | $          | 3.9                               |       |   |   | $ | 3.8 |   |   |
| Liquids inventory                              |       |                    | 9.8        |                              |       |   | 9.9 |   |   |
| Natural gas and  natural gas liquids inventory |       |                    | 105.8      |                              |       |   | 103.4 |   |   |
|                                           |       |                    | $          | 119.5                             |       |   |   | $ | 117.1 |   |   |

 

Our inventory at June 30,2007 is net of charges of $1.5 million we recorded to reduce the cost basis ofour natural gas and natural gas liquids, or NGLs, inventory to reflect marketvalue. The lower of cost or market adjustments are included in Cost of naturalgas on our Consolidated Statements of Income.

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**5.**                 PROPERTY,PLANT AND EQUIPMENT

Property,Plant and Equipment is comprised of the following:

| ** **                                          | ** ** | **June 30,  2007** | ** ** | **December  31,  2006** | ** ** |
|-----------------------------------------------------|------------|-------------------------|------------|-----------------------------------|------------|
| ** **                                          | ** ** | **(in millions)**  | ** ** |
| Land                                                |       | $                       | 14.8       |                              |       | $ | 14.3 |   |   |
| Rights-of-way                                       |       | 306.5                   |       |                              | 298.6      |   |   |
| Pipelines                                           |       | 2,385.3                 |       |                              | 2,320.8    |   |   |
| Pumping  equipment, buildings and tanks             |       | 774.2                   |       |                              | 747.4      |   |   |
| Compressors,  meters, and other operating equipment |       | 438.2                   |       |                              | 418.1      |   |   |
| Vehicles, office  furniture and equipment           |       | 121.3                   |       |                              | 112.4      |   |   |
| Processing and  treating plants                     |       | 140.8                   |       |                              | 86.4       |   |   |
| Construction in  progress                           |       | 1,435.8                 |       |                              | 733.6      |   |   |
| Total property, plant and equipment                 |       | 5,616.9                 |       |                              | 4,731.6    |   |   |
| Accumulated  depreciation                           |       | (975.0                  | )          |                              | (906.7     | ) |   |
| Net property,  plant and equipment                  |       | $                       | 4,641.9    |                              |       | $ | 3,824.9 |   |   |

 

**6.**                 INCOMETAXES

We are not a taxableentity for U.S. federal income tax purposes, or for the majority of states thatimpose income tax. These taxes on our net income are generally borne by ourunitholders through the allocation of taxable income. In May 2006, theState of Texas enacted substantial changes to its tax structure to impose a newtax based on modified gross margin, which began in 2007. Under the provisionsof Statement of Financial Accounting Standards (“SFAS”) No. 109, *Accounting for Income Taxes*, we havedetermined that this tax is an income tax. Our income tax expense is $1.3million  and $2.4 million for the threeand six month periods ended June 30, 2007, which we computed by applying a0.56% apportioned state income tax rate to taxable margin, as defined in theState of Texas statutes. At June 30, 2007 we have included a currentincome tax payable of $2.4 million in Property and other taxes payable and adeferred income tax asset of $0.4 million in Other assets, net on ourConsolidated Statements of Financial Position.

**7.****                 DEBT**

***Credit Facility***

At June 30, 2007 and December 31, 2006, wehad no amounts outstanding under our Credit Facility and had letters of credittotaling $90.0 million and $59.3 million, respectively. The amounts we mayborrow under the terms of our Credit Facility are reduced by the principalamount of our commercial paper issuances and the balance of our letters ofcredit outstanding. At June 30, 2007, we could borrow $765.0 millionunder the terms of our Credit Facility without consideration to additionalborrowings under our commercial paper program.

On April 4, 2007 weentered into the Second Amended and Restated Credit Agreement (Credit Facility)which among other things: (i) increases the maximum principal amount ofcredit available to us at any one time from $1 billion to $1.25 billion; (ii) givesus the right to request increases in the maximum principal amount of creditavailable at any one time from $1.25 billion to $1.5 billion; (iii) eliminatesthe sublimit on letters of credit; (iv) provides for a five-year facilitythat matures April 4, 2012 and grants us the option to request annualextensions of maturity and a one-year term out period upon maturity; (v) modifiesour leverage ratio to include in the calculations of EBITDA (as defined in theSecond Amended and Restated Credit Agreement) pro forma adjustments formaterial projects and to exclude from the calculation of Consolidated FundedDebt (as defined in the Second Amended and Restated Credit Agreement) certainamounts of preferred securities and subordinated debt that we or our 

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designatedsubsidiaries may issue in the future; and (vi) eliminates our coverageratio financial covenant. Our Credit Facility continues to support ourcommercial paper program.

***Commercial Paper Program***

Under the terms of ourcommercial paper program, we can issue up to $600 million of commercial paper. AtJune 30, 2007, we had outstanding $393.3 million of commercial paper, netof unamortized discount of $1.7 million, bearing interest at a weighted averagerate of 5.48%. At December 31, 2006, we had $443.7 million ofcommercial paper outstanding, net of $1.3 million of unamortized discount,at a weighted average interest rate of 5.45%. At June 30, 2007, we couldissue an additional $205.0 million in principal amount under the terms of ourcommercial paper program.

**8.**                 PARTNERS’CAPITAL

Thefollowing table sets forth the distributions, as approved by the Board ofDirectors of Enbridge Energy Management, L.L.C. (“Enbridge Management”) duringthe six months ended June 30, 2007:

| **Distribution** Declaration Date | ** ** | ** **             | **Distribution** Payment Date | ** **            | **Record** Date | ** ** | **Distribution** per Unit | ** ** | **Cash** available for distribution | ** **                                                          | **Amount of** Distribution of i-units to i-unit Holders(1) | ** ** | **Amount of** Distribution of Class C  units to Class C  unit Holders(2) | ** ** | **Retained** from General Partner(3) | ** ** | **Distribution** of Cash | ** ** |
|----------------------------------------|------------|------------------------|------------------------------------|-----------------------|-----------------|------------|--------------------------------|------------|------------------------------------------|---------------------------------------------------------------------|---------------------------------------------------------------------------|------------|---------------------------------------------------------------------------------------------------|------------|--------------------------------------|------------|-------------------------------|------------|
| ** **                             | ** ** | ** **             | ** **                         | ** **            | ** **      | ** ** | ** **                     | ** ** | ** **                               | **(in millions, except per unit amounts)** | ** **                                                                | ** ** | ** **                                                                                        |
| January 26,  2007                 |       | February 14, 2007 |                               | February 6, 2007 |            |       | $                              | 0.925      |                                     |                                                                |                                                                      | $          | 80.0                                                                                              |       |                                 |       | $                             | 11.7       |   |   |   | $ | 10.2 |   |   |   | $ | 0.5 |   |   |   | $ | 57.6 |   |   |
| April 26, 2007                    |       | May 15, 2007      |                               | May 7, 2007      |            |       | $                              | 0.925      |                                     |                                                                |                                                                      | $          | 86.6                                                                                              |       |                                 |       | $                             | 11.9       |   |   |   | $ | 15.9 |   |   |   | $ | 0.6 |   |   |   | $ | 58.2 |   |   |

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(1)            During 2007, in lieu of cashdistributions, the Partnership issued 433,926 i-units to EnbridgeManagement.

(2)            During 2007, in lieu of cashdistributions, the Partnership issued 458,503 Class C units to our Class Cunitholders.

(3)            The Partnership retains an amount equal totwo percent of the i-unit and Class C unit distribution from theGeneral Partner in respect of its two percent general partner interest.

***Issuance of Class A common units***

In May 2007, weissued 5.3 million Class A common units at a price of $58.00 per unit, forproceeds of approximately $301.9 million, net of underwriters’ discounts,commissions and issuance costs. In addition, our general partner contributedapproximately $6.1 million to us to maintain its two percent general partnerinterest. We used the proceeds from this offering partially to reduceoutstanding commercial paper we previously issued to finance a portion of ourcapital expansion projects. We invested the remaining amount in short-term commercialpaper for use in future periods to fund additional expenditures under ourcapital expansion projects.

***Private Placement of Class C Units***

In April 2007, weissued and sold 4.7 million Class C units at a price of $53.11 per Class Cunit to CDP Infrastructure Fund G.P. (“CDP”), 0.9 million Class C units toTortoise Infrastructure Corporation and 0.3 million Class C units toTortoise Energy Capital Corporation.  Wesold the Class C units in a private transaction exempt from registrationunder Section 4(2) of the Securities Act. We received proceeds ofapproximately $314.4 million, net of expenses associated with the privateplacement. In addition, our general partner contributed approximately $6.4million to us to maintain its two percent general partner interest. We used the proceeds from thisoffering partially to reduce outstanding commercial paper we previously issuedto finance a portion of our capital expansion program, including theEast Texas and Southern Access expansion projects.

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**9.**                 COMMITMENTS,CONTINGENCIES AND ENVIRONMENTAL LIABILITIES

***Environmental Liabilities***

We are subject to federal and state laws andregulations relating to the protection of the environment. Environmental riskis inherent to the gathering, transportation, storage and processing of liquidhydrocarbon and natural gas products and we could, at times, be subject toenvironmental cleanup and enforcement actions. We manage this environmentalrisk through appropriate environmental policies and practices to minimize anyimpact our operations may have on the environment.

As of June 30, 2007 and December 31, 2006,we have recorded $2.7 million and $4.1 million, respectively, incurrent liabilities and $3.7 million and $3.3 million, respectively,in long-term liabilities, primarily to address remediation ofcontaminated sites, asbestos containing materials, management of hazardouswaste material disposal, and outstanding air quality measures for certain ofour liquids and natural gas assets.

In January 2007, we detected a leak on Line 14 ofour Lakehead system, near the Owen, Wisconsin pump station. We immediately shutthe pipeline down and dispatched emergency response crews to overseecontainment, cleanup and repair of the pipeline. We spent approximately $0.9million to recover the barrels released, complete excavation, clean-up andrepairs to return the line to service. We have applied pressure restrictions tothe line as we work with federal and state environmental and pipeline safetyregulators to investigate the cause of the rupture. Such pressure restrictionshave not materially affected throughput on the system. We have the potential ofincurring additional expenditures to remediate any condition on the line thatis determined to have caused the rupture.

In February 2007, acontractor undertaking work in Rusk County, Wisconsin on the Enbridge SouthernLights project punctured the adjacent Line 14 pipeline, resulting in a releaseof crude oil estimated at 3,000 barrels.  As the spill was largely contained within theditch used for construction, environmental impact was minimized.   Impact to customers was also minimized as theline was repaired and returned to service in less than two days. We continueinvestigating this incident and have spent approximately $1.4 million of theestimated $2.6 million associated with the repair and cleanup, which werecorded as a liability and a receivable, since we will recover these cost fromthe parties responsible for the damage. Any further exposure or impact relatedto this incident is not believed to be material.

***Legal Proceedings***

We are a participant invarious legal proceedings arising in the ordinary course of business. Some ofthese proceedings are covered, in whole or in part, by insurance. We believethat the outcome of all these proceedings will not, individually or in theaggregate, have a material adverse effect on our financial condition.

**10.**          DERIVATIVEFINANCIAL INSTRUMENTS—COMMODITY PRICE RISK

Our net income and cashflows are subject to volatility stemming from changes in commodity prices ofnatural gas, NGLs, condensate and fractionation margins (the relative pricedifferential between NGL sales and the offsetting natural gas purchases).  Our exposure to commodity price risk existswithin our Natural Gas and Marketing segments. To mitigate the volatility of our cash flows, we use derivativefinancial instruments (i.e., futures, forwards, swaps, options and otherfinancial instruments with similar characteristics) to manage the risksassociated with market fluctuations in commodity prices.  Based on our risk management policies, all ofour derivative financial instruments are employed in connection with anunderlying asset, liability and/or forecasted transaction and are not enteredinto with the objective of speculating on commodity prices.

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***Accounting Treatment ***

All derivative financial instruments are recorded inthe consolidated financial statements at fair market value and are adjustedeach period for changes in the fair market value (“mark-to-market”).  The fair market value of these derivativefinancial instruments reflects the estimated amounts that we would pay orreceive, other than in a forced or liquidation sale, to terminate or close thecontracts at the reporting date, taking into account the current unrealizedlosses or gains on open contracts.  Weuse actively traded external market quotes and indices to value substantiallyall of the derivative financial instruments we utilize.

Under the guidance of SFAS No. 133, if aderivative financial instrument does not qualify as a hedge, or is notdesignated as a hedge, the derivative is adjusted to its fair market value, ormarked-to-market, each period with the increases and decreases infair value recorded in our Consolidated Statements of Income as increases anddecreases in Cost of natural gas for our commodity-based derivatives.  Cash flow is only impacted to the extent theactual derivative contract is settled by making or receiving a payment to orfrom the counterparty or by making or receiving a payment for entering into a contractthat exactly offsets the original derivative contract.  Typically, we settle our derivative contractswhen the physical transaction that underlies the derivative financialinstrument occurs.

If a derivative financialinstrument qualifies and is designated as a cash flow hedge, a hedge of aforecasted transaction or future cash flows, any unrealized mark-to-market gainor loss is deferred in Accumulated other comprehensive income (“AOCI”), acomponent of Partners’ Capital, until the underlying hedged transactionoccurs.  To the extent that the hedgeinstrument is effective in offsetting the transaction being hedged, there is noimpact to the income statement.  Atinception and on a quarterly basis, we formally assess whether the hedgecontract is highly effective in offsetting changes in cash flows of hedgeditems.  Any ineffective portion of a cashflow hedge’s change in fair market value is recognized each period inearnings.  Realized gains and losses onderivative financial instruments that are designated as hedges and qualify forhedge accounting are included in Cost of natural gas in the period the hedgedtransaction occurs.  Gains and lossesdeferred in AOCI related to cash flow hedges, for which hedge accounting hasbeen discontinued, remain in AOCI until the underlying physical transactionoccurs unless it is probable that the forecasted transaction will not occur bythe end of the originally specified time period, or within an additionaltwo-month period of time thereafter. Generally, our preference is for our derivative financial instruments toreceive hedge accounting treatment whenever possible, to mitigate the non-cashearnings volatility that arises under mark-to-market accountingtreatment.  To qualify for cash flowhedge accounting as set forth in SFAS No. 133, very specific requirements mustbe met in terms of hedge structure, hedge objective and hedge documentation.

***Non-Qualified Hedges***

Many of our derivative financial instruments qualifyfor hedge accounting treatment under the specific requirements of SFASNo. 133.  As discussed in Note 15 toour consolidated financial statements included in our Annual Report onForm 10-K for the year ended December 31, 2006, we have fourtransaction types where the hedge structure does not meet the requirements topermit application of hedge accounting and are referred to as“non-qualified.”  Non-qualifiedderivative financial instruments are marked-to-market each periodwith the change in fair value, representing unrealized gains and losses,included in Cost of natural gas in our Consolidated Statements of Income.  These mark-to-market adjustmentsproduce a degree of earnings volatility that can often be significant fromperiod to period, but have no cash flow impact relative to changes in marketprices.  The cash flow impact occurs whenthe underlying physical transaction takes place in the future and when theassociated financial instrument contract settlement is made. 

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Thefollowing table presents the mark-to-market gains and losses associated with changesin the fair value of our commodity price derivative financial instruments,which are recorded as an element of Cost of natural gas in our ConsolidatedStatements of Income and disclosed as a reconciling item on our Statements ofCash Flows:

| ** **                                                   | ** ** | **Three months**   | ** ** | **Six months**     | ** ** |
|--------------------------------------------------------------|------------|-------------------------|------------|-------------------------|------------|
| ** **                                                   | ** ** | **ended June 30,** | ** ** | **ended June 30,** | ** ** |
| **Derivative fair value gains (losses)** | ** ** | ** **              | ** ** | **2007**                | ** ** | **2006** | ** ** | **2007** | ** ** | **2006** | ** ** |
| ** **                                                   | ** ** | **(in millions)**  | ** ** |
| Natural Gas  segment                                         |       |                    |       |                    |       |   |   |   |   |
| Ineffectiveness                                              |       | $                       | 0.2        |                    | $          | (0.1 | ) | $ | 0.3 |   | $ | (0.1 | ) |
| Non-qualified hedges                                         |       | (2.8                    | )          | (3.6                    | )          | (6.0 | ) | (1.8 | ) |
| Marketing                                                    |       |                    |       |                    |       |   |   |   |   |
| Non-qualified hedges                                         |       | 6.3                     |       | 5.4                     |       | (6.9 | ) | 31.3 |   |
| Derivative fair value  gains (losses)                        |       | $                       | 3.7        |                    | $          | 1.7 |   | $ | (12.6 | ) | $ | 29.4 |   |
|                                                              |            |                         |            |                         |            |  |  |  |  |  |  |  |  |  |  |

 

We record the change infair value of our cash flow hedges in AOCI until the derivative financial instrumentsare settled, at which time they are reclassified from AOCI to earnings. Alsoincluded in AOCI are unrecognized losses of approximately $3.4 millionassociated with cash flow hedges that were subsequently de-designated. Theselosses are reclassified to earnings over the periods during which theoriginally hedged forecasted transactions affect earnings. For the three andsix month periods ended June 30, 2007, we reclassified losses of $21.0million and $37.2 million, respectively, from AOCI to Cost of natural gas onour Consolidated Statements of Income for the fair value of derivativefinancial instruments that were settled. For the three and six month periods ended June 30, 2006, we reclassifiedlosses of $14.9 million and $39.7 million, respectively, from AOCI to Costof natural gas on our Consolidated Statements of Income for the fair value ofderivative financial instruments that were settled.

***Derivative Positions***

Ourderivative financial instruments are included at their fair values in the ConsolidatedStatements of Financial Position as follows:

| ** **                   | ** ** | **June 30,  2007** | ** ** | **December 31,  2006** | ** ** |
|------------------------------|------------|-------------------------|------------|-----------------------------|------------|
| ** **                   | ** ** | **(in millions)**  | ** ** |
| Other current  assets        |       | $                       | 5.1        |                        |       | $ | 7.2 |   |   |
| Other assets, net            |       | 20.8                    |       |                        | 11.0       |   |   |
| Accounts payable  and other  |       | (87.8                   | )          |                        | (57.2      | ) |   |
| Other long-term  liabilities |       | (162.3                  | )          |                        | (136.4     | ) |   |
|                         |       | $                       | (224.2     | )                           |       | $ | (175.4 | ) |   |

 

The increase in our obligation associated withderivative activities is primarily due to the increase in forward natural gasprices from December 31, 2006 to June 30, 2007. The Partnership’sportfolio of derivative financial instruments is largely comprised of long-termfixed price natural gas sales and purchase agreements.

We do not require collateral or other security fromthe counterparties to our derivative financial instruments, all of which were rated“BBB+” or better by the major credit rating agencies.

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**11.**          SEGMENTINFORMATION

Our business is divided into operating segments,defined as components of the enterprise, about which financial information isavailable and evaluated regularly by our Chief Operating Decision Maker indeciding how resources are allocated and performance is assessed.

Each of ourreportable segments is a business unit that offers different services andproducts that is managed separately, since each business segment requiresdifferent operating strategies. We have segregated our business activities intothree distinct operating segments:

·       Liquids;

·       NaturalGas; and

·       Marketing.

Thefollowing tables present financial information about our business segments:

|                                                | ** ** | **As of and for the three months ended June 30, 2007** | ** ** |
|------------------------------------------------|------------|----------------------------------------------------------------------------------------------------------|------------|
| ** **                                     | ** ** | **Liquids**                                                                                              | ** ** | **Natural Gas** | ** ** | **Marketing** | ** ** | **Corporate** (1) | ** ** | **Total** | ** ** |
| ** **                                     | ** ** | **(in millions)**                                                                                   | ** ** |
| Total revenue                                  |       | $                                                                                                        | 129.4      |   |   | $ | 1,384.4 |   |   |   | $ | 954.3 |   |   |   | $ | — |   |   | $ | 2,468.1 |   |
| Less:  Intersegment revenue                    |       | —                                                                                                   |       |   | 670.1 |   |   |   | 59.3 |   |   |   | — |   |   | 729.4 |   |
| Operating revenue                              |       | 129.4                                                                                                    |       |   | 714.3 |   |   |   | 895.0 |   |   |   | — |   |   | 1,738.7 |   |
| Cost of natural  gas (Notes 5 and 10)          |       | —                                                                                                   |       |   | 591.8 |   |   |   | 883.8 |   |   |   | — |   |   | 1,475.6 |   |
| Operating and  administrative                  |       | 40.6                                                                                                     |       |   | 60.9 |   |   |   | 1.9 |   |   |   | 1.7 |   |   | 105.1 |   |
| Power                                          |       | 27.3                                                                                                     |       |   | — |   |   |   | — |   |   |   | — |   |   | 27.3 |   |
| Depreciation and  amortization (Note 6)        |       | 16.7                                                                                                     |       |   | 22.4 |   |   |   | 0.7 |   |   |   | — |   |   | 39.8 |   |
| Operating income                               |       | 44.8                                                                                                     |       |   | 39.2 |   |   |   | 8.6 |   |   |   | (1.7 | ) |   | 90.9 |   |
| Interest expense                               |       | —                                                                                                   |       |   | — |   |   |   | — |   |   |   | 21.5 |   |   | 21.5 |   |
| Other income                                   |       | —                                                                                                   |       |   | — |   |   |   | — |   |   |   | 0.5 |   |   | 0.5 |   |
| Income before income tax expense               |       | 44.8                                                                                                     |       |   | 39.2 |   |   |   | 8.6 |   |   |   | (22.7 | ) |   | 69.9 |   |
| Income tax expense                             |       | —                                                                                                   |       |   | — |   |   |   | — |   |   |   | 1.3 |   |   | 1.3 |   |
| Net income                                     |       | $                                                                                                        | 44.8       |   |   | $ | 39.2 |   |   |   | $ | 8.6 |   |   |   | $ | (24.0 | ) |   | $ | 68.6 |   |
| Capital  expenditures (excluding acquisitions) |       | $                                                                                                        | 270.2      |   |   | $ | 219.2 |   |   |   | $ | 0.3 |   |   |   | $ | 2.5 |   |   | $ | 492.2 |   |

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(1)                Corporateconsists of interest expense, interest income and certain other costs such asfranchise and income taxes, which are not allocated to our business segments. 

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|                                                | ** ** | **As of and for the three months ended June 30, 2006** | ** ** |
|------------------------------------------------|------------|----------------------------------------------------------------------------------------------------------|------------|
| ** **                                     | ** ** | **Liquids**                                                                                              | ** ** | **Natural Gas** | ** ** | **Marketing** | ** ** | **Corporate** (1) | ** ** | **Total** | ** ** |
| ** **                                     | ** ** | **(in millions)**                                                                                   | ** ** |
| Total revenue                                  |       | $                                                                                                        | 124.9      |   |   | $ | 1,231.3 |   |   |   | $ | 667.6 |   |   |   | $ | — |   |   | $ | 2,023.8 |   |
| Less:  Intersegment revenue                    |       | —                                                                                                   |       |   | 557.8 |   |   |   | 41.3 |   |   |   | — |   |   | 599.1 |   |
| Operating revenue                              |       | 124.9                                                                                                    |       |   | 673.5 |   |   |   | 626.3 |   |   |   | — |   |   | 1,424.7 |   |
| Cost of natural  gas                           |       | —                                                                                                   |       |   | 566.9 |   |   |   | 618.7 |   |   |   | — |   |   | 1,185.6 |   |
| Operating and administrative                   |       | 35.1                                                                                                     |       |   | 50.0 |   |   |   | 1.5 |   |   |   | 0.7 |   |   | 87.3 |   |
| Power                                          |       | 24.2                                                                                                     |       |   | — |   |   |   | — |   |   |   | — |   |   | 24.2 |   |
| Depreciation and  amortization                 |       | 15.9                                                                                                     |       |   | 17.9 |   |   |   | 0.1 |   |   |   | 0.1 |   |   | 34.0 |   |
| Operating income                               |       | 49.7                                                                                                     |       |   | 38.7 |   |   |   | 6.0 |   |   |   | (0.8 | ) |   | 93.6 |   |
| Interest expense                               |       | —                                                                                                   |       |   | — |   |   |   | — |   |   |   | 27.6 |   |   | 27.6 |   |
| Other income                                   |       | —                                                                                                   |       |   | — |   |   |   | — |   |   |   | 4.4 |   |   | 4.4 |   |
| Net income                                     |       | $                                                                                                        | 49.7       |   |   | $ | 38.7 |   |   |   | $ | 6.0 |   |   |   | $ | (24.0 | ) |   | $ | 70.4 |   |
| Capital  expenditures (excluding acquisitions) |       | $                                                                                                        | 34.4       |   |   | $ | 148.0 |   |   |   | $ | 0.5 |   |   |   | $ | 3.6 |   |   | $ | 186.5 |   |

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(1)                Corporateconsists of interest expense, interest income and certain other costs such asfranchise and income taxes, which are not allocated to our business segments.

|                                                     | ** ** | **As of and for the six months ended June 30, 2007** | ** ** |
|-----------------------------------------------------|------------|--------------------------------------------------------------------------------------------------------|------------|
| ** **                                          | ** ** | **Liquids**                                                                                            | ** ** | **Natural Gas** | ** ** | **Marketing** | ** ** | **Corporate** (1) | ** ** | **Total** | ** ** |
| ** **                                          | ** ** | **(in millions)**                                                                                 | ** ** |
| Total revenue                                       |       | $                                                                                                      | 262.2      |   |   | $ | 2,708.7 |   |   |   | $ | 1,843.7 |   |   |   | $ | — |   |   | $ | 4,814.6 |   |
| Less:  Intersegment revenue                         |       | —                                                                                                 |       |   | 1,238.9 |   |   |   | 124.3 |   |   |   | — |   |   | 1,363.2 |   |
| Operating revenue                                   |       | 262.2                                                                                                  |       |   | 1,469.8 |   |   |   | 1,719.4 |   |   |   | — |   |   | 3,451.4 |   |
| Cost of natural  gas (Notes 5 and 10)               |       | —                                                                                                 |       |   | 1,255.0 |   |   |   | 1,704.9 |   |   |   | — |   |   | 2,959.9 |   |
| Operating and  administrative                       |       | 74.3                                                                                                   |       |   | 122.2 |   |   |   | 3.5 |   |   |   | 2.8 |   |   | 202.8 |   |
| Power                                               |       | 57.4                                                                                                   |       |   | — |   |   |   | — |   |   |   | — |   |   | 57.4 |   |
| Depreciation and  amortization (Note 6)             |       | 33.1                                                                                                   |       |   | 42.4 |   |   |   | 0.8 |   |   |   | — |   |   | 76.3 |   |
| Operating income                                    |       | 97.4                                                                                                   |       |   | 50.2 |   |   |   | 10.2 |   |   |   | (2.8 | ) |   | 155.0 |   |
| Interest expense                                    |       | —                                                                                                 |       |   | — |   |   |   | — |   |   |   | 46.8 |   |   | 46.8 |   |
| Other income                                        |       | —                                                                                                 |       |   | — |   |   |   | — |   |   |   | 1.9 |   |   | 1.9 |   |
| Income before income tax expense                    |       | 97.4                                                                                                   |       |   | 50.2 |   |   |   | 10.2 |   |   |   | (47.7 | ) |   | 110.1 |   |
| Income tax expense                                  |       | —                                                                                                 |       |   | — |   |   |   | — |   |   |   | 2.4 |   |   | 2.4 |   |
| Net income                                          |       | $                                                                                                      | 97.4       |   |   | $ | 50.2 |   |   |   | $ | 10.2 |   |   |   | $ | (50.1 | ) |   | $ | 107.7 |   |
| Total assets                                        |       | $                                                                                                      | 2,279.0    |   |   | $ | 3,074.0 |   |   |   | $ | 353.1 |   |   |   | $ | 170.4 |   |   | $ | 5,876.5 |   |
| Capital  expenditures (excluding acquisitions) |       | $                                                                                                      | 493.4      |   |   | $ | 385.9 |   |   |   | $ | 1.5 |   |   |   | $ | 10.7 |   |   | $ | 891.5 |   |

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(1)                Corporateconsists of interest expense, interest income and certain other costs such asfranchise and income taxes, which are not allocated to our business segments.

15

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|                                                     | ** ** | **As of and for the six months ended June 30, 2006** | ** ** |
|-----------------------------------------------------|------------|--------------------------------------------------------------------------------------------------------|------------|
| ** **                                          | ** ** | **Liquids**                                                                                            | ** ** | **Natural Gas** | ** ** | **Marketing** | ** ** | **Corporate** (1) | ** ** | **Total** | ** ** |
| ** **                                          | ** ** | **(in millions)**                                                                                 | ** ** |
| Total revenue                                       |       | $                                                                                                      | 247.5      |   |   | $ | 2,833.2 |   |   |   | $ | 1,634.0 |   |   | $ | — |   | $ | 4,714.7 |   |
| Less:  Intersegment revenue                         |       | —                                                                                                 |       |   | 1,288.7 |   |   |   | 112.7 |   |   | — |   | 1,401.4 |   |
| Operating revenue                                   |       | 247.5                                                                                                  |       |   | 1,544.5 |   |   |   | 1,521.3 |   |   | — |   | 3,313.3 |   |
| Cost of natural  gas                                |       | —                                                                                                 |       |   | 1,340.4 |   |   |   | 1,492.9 |   |   | — |   | 2,833.3 |   |
| Operating and  administrative                       |       | 63.7                                                                                                   |       |   | 93.7 |   |   |   | 2.6 |   |   | 1.2 |   | 161.2 |   |
| Power                                               |       | 50.5                                                                                                   |       |   | — |   |   |   | — |   |   | — |   | 50.5 |   |
| Depreciation and  amortization                      |       | 31.8                                                                                                   |       |   | 34.5 |   |   |   | 0.2 |   |   | 0.2 |   | 66.7 |   |
| Operating income                                    |       | 101.5                                                                                                  |       |   | 75.9 |   |   |   | 25.6 |   |   | (1.4 | ) | 201.6 |   |
| Interest expense                                    |       | —                                                                                                 |       |   | — |   |   |   | — |   |   | 55.5 |   | 55.5 |   |
| Other income                                        |       | —                                                                                                 |       |   | — |   |   |   | — |   |   | 5.4 |   | 5.4 |   |
| Net income                                          |       | $                                                                                                      | 101.5      |   |   | $ | 75.9 |   |   |   | $ | 25.6 |   |   | $ | (51.5 | ) | $ | 151.5 |   |
| Total assets                                        |       | $                                                                                                      | 1,704.7    |   |   | $ | 2,421.6 |   |   |   | $ | 276.5 |   |   | $ | 85.1 |   | $ | 4,487.9 |   |
| Capital  expenditures (excluding acquisitions) |       | $                                                                                                      | 50.8       |   |   | $ | 229.1 |   |   |   | $ | 0.9 |   |   | $ | 4.4 |   | $ | 285.2 |   |

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(1)                Corporateconsists of interest expense, interest income and certain other costs such asfranchise and income taxes, which are not allocated to our business segments.

**12.**          SUBSEQUENTEVENT

***Distribution to Partners***

On July 27, 2007, theBoard of Directors of Enbridge Management declared a distribution payable toour partners on August 14, 2007. The distribution will be paid tounitholders of record as of August 6, 2007, of our available cash of $92.6million at June 30, 2007, or $0.925 per common unit. Of this distribution,$63.7 million will be paid in cash, $12.1 million will be distributed in i-unitsto our i-unitholder, $16.2 million will be distributed in Class Cunits to the holders of our Class C units and $0.6 million will beretained from the General Partner in respect of the i-unit and Class Cunit distributions.

**13.**          RECENTACCOUNTING PRONOUNCEMENTS NOT YET ADOPTED

In February 2007, the Financial AccountingStandards Board (FASB) issued SFAS No. 159, *The Fair Value Option for Financial Assets and Liabilities.*Thisstatement provides companies with an option to report certain financial assetsand financial liabilities at fair value. The objective of SFAS No. 159 isto reduce the volatility in earnings caused by measuring related assets andliabilities differently without having to apply complex hedge accountingprovisions. SFAS No. 159 also establishes presentation and disclosurerequirements designed to facilitate comparisons between companies that choose differentmeasurement attributes for similar types of assets and liabilities. Theprovisions of SFAS No. 159 are effective at the beginning of our firstfiscal year that begins after November 15, 2007 as we have elected not toearly adopt the provisions of SFAS No. 159. We do not expect our adoptionof SFAS No. 159 to have a material affect on our Consolidated FinancialStatements.

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**Item2.**                        Management’sDiscussion and Analysis of Financial Condition and Results of Operations

The following discussionand analysis of our financial condition and results of operations should beread together with our Consolidated Financial Statements and the accompanyingnotes included in “Item 1. Financial Statements” of this Quarterly Reporton Form 10-Q and with the information included in our Annual Reporton Form 10-K for the year ended December 31, 2006.

**RESULTS OFOPERATIONS—OVERVIEW**

We provide servicesto our customers and returns for our unitholders primarily through thefollowing activities:

·       Interstate pipelinetransportation and storage of crude oil and liquid petroleum;

·       Gathering, treating,processing and transportation of natural gas and natural gas liquids, or NGLs,through pipelines and related facilities; and

·       Providing supply,transportation and sales services, including purchasing and selling natural gasand NGLs.

We conduct our business through three businesssegments: Liquids, Natural Gas and Marketing. These segments are strategicbusiness units established by senior management to facilitate the achievementof our long-term objectives, to aid in resource allocation decisions andto assess operational performance.

We primarily provide fee-based services to ourcustomers to minimize our exposure to commodity price risks. However, in ournatural gas and marketing businesses, a portion of our earnings and cash flowsare exposed to movements in the prices of natural gas and NGLs. To substantiallymitigate this exposure and to provide stability to our cash flow, we enter intoderivative financial instrument transactions. Certain of these transactionsqualify for hedge accounting under SFAS No. 133, *Accounting for Derivative Transactions and HedgingActivities*; some, however, must be accounted for using the mark-to-marketmethod of accounting and this can expose our earnings to significantvolatility.

Thefollowing table reflects our operating income by business segment and corporatecharges for the three and six month periods ended June 30:

| ** **                              | ** ** | **Three months ended  June 30,** | ** ** | **Six months ended  June 30,** | ** ** |
|-----------------------------------------|------------|-------------------------------------------------|------------|-----------------------------------------------|------------|
| ** **                              | ** ** | **  2007  **                | ** ** | **  2006  **              | ** ** | **2007** | ** ** | **2006** | ** ** |
| ** **                              | ** ** | **(in millions)**                          | ** ** |
| **Operating Income**                    | ** ** |                                            | ** ** |                                          |       |   | ** ** |   |   | ** ** |   | ** ** |   |   |
| Liquids                                 |       |                                            | $          | 44.8                                          |       |   |   | $ | 49.7 |   |   | $ | 97.4 |   | $ | 101.5 |   |   |
| Natural Gas                             |       |                                            | 39.2       |                                          |       |   | 38.7 |   |   | 50.2 |   | 75.9 |   |   |
| Marketing                               |       |                                            | 8.6        |                                          |       |   | 6.0 |   |   | 10.2 |   | 25.6 |   |   |
| Corporate, operating and administrative |       |                                            | (1.7       | )                                             |       |   | (0.8 | ) |   | (2.8 | ) | (1.4 | ) |   |
| **Total Operating Income**              |       |                                            | 90.9       |                                          |       |   | 93.6 |   |   | 155.0 |   | 201.6 |   |   |
| Interest expense                        |       |                                            | 21.5       |                                          |       |   | 27.6 |   |   | 46.8 |   | 55.5 |   |   |
| Other income                            |       |                                            | 0.5        |                                          |       |   | 4.4 |   |   | 1.9 |   | 5.4 |   |   |
| Income tax expense                      |       |                                            | 1.3        |                                          |       |   | — |   |   | 2.4 |   | — |   |   |
| **Net  Income**                         |       |                                            | $          | 68.6                                          |       |   |   | $ | 70.4 |   |   | $ | 107.7 |   | $ | 151.5 |   |   |

 

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***Summary Analysis of Operating Results***

*Liquids*

Our Liquids segmentproduced operating income of $44.8 million and $97.4 million for the three andsix month periods ended June 30, 2007, a slight decrease compared to the$49.7 million and $101.5 million earned in the comparable periods of 2006. Theoperating income of our Liquids business was impacted by increases in theaverage tariffs on all three of our Liquids systems that went into effect July 1,2006, coupled with annual tariff rate adjustments in April 1, 2007 forhistorical pipeline expansions known as the SEP II, Terrace and Facilitiessurcharges. Operating income was also positively affected by the increase incontract storage fees generated by our Cushing terminal associated with theadditional storage tanks we completed in late 2006. Operating income for thequarter was negatively affected by lower delivery volumes associated withscheduled and unscheduled third-party upgrader and refinery turnarounds duringthe quarter. Higher operating expenses, primarily associated with our pipelineintegrity management program in addition to higher utility rates, alsocontributed to lower operating income.

*Natural Gas*

Operating income from our Natural Gas segment slightlyincreased by $0.5 million to $39.2 million for the three month period ended June 30,2007, from $38.7 million for the comparable period in 2006. Operating incomefor the six month period ended June 30, 2007 decreased by $25.7 million to$50.2 million, from $75.9 million for the comparable period in 2006.

For the threemonths ended June 30, 2007 the change in contribution from our Natural Gassegment is primarily attributable to the following:

·       Increased natural gastreating and processing capacity from the completion of the initial phase ofour East Texas expansion and increased processing capacity on our Anadarkosystem.

·       Volumegrowth within our North Texas systems due to significant production increasesand strong drilling activity in the Barnett Shale formation.

·       Partiallyoffsetting the volume growth and increased processing and treating capacitywere lower revenue less cost of natural gas derived from our processing assetsdue to a less favorable pricing environment in the current quarter than in thesame period of 2006.

·       Increased operating andadministrative costs associated with the increase in volumes and expansion ofour natural gas systems as well as pipeline integrity management costs.

For the six monthsended June 30, 2007, in addition to the factors discussed above, theoperating results of our Natural Gas segment were also affected by thefollowing:

·       An increase in natural gasmeasurement losses on two of our major gathering systems.

·       Operationalinefficiencies at our Zybach plant, in part caused by fouling of the plant bycontaminated water in the natural gas stream, which reduced NGL production andthe associated processing revenue.

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*Marketing*

Operating incomefrom our Marketing segment increased by $2.6 million to $8.6 million for thethree month period ended June 30, 2007, from $6.0 million for thecomparable period in 2006. Operating income for the six month period ended June 30,2007 decreased by $15.4 million to $10.2 million, from $25.6 million for thecomparable period in 2006. The operating results of our Marketing segment arepredominantly the result of the following factors:

·       Increasedaccess to preferred natural gas markets associated with our natural gas systemexpansions and other initiatives, as well as stronger pricing for natural gasin secondary markets.

·       Unrealized,non-cash mark-to-market net gains of $6.3 million and net losses of $6.9million for the three and six month periods ended June 30, 2007,respectively, that resulted from the changes in market value of our derivativefinancial instruments that do not qualify for hedge accounting.

·       Salesof natural gas inventory for approximately $12 million that we realized for thesix months ended June 30, 2007, including approximately $6 million ofgains from the settlement of derivative financial instruments hedging ournatural gas inventory.

***Derivative Transactions and Hedging Activities***

We record all derivative financial instruments in theconsolidated financial statements at fair market value pursuant to therequirements of SFAS No. 133. For those derivative financial instrumentsthat do not qualify for hedge accounting, all changes in fair market value arerecorded through our Consolidated Statements of Income each period. The fairmarket value of these derivative financial instruments reflects the estimatedamounts that we would pay or receive to terminate or close the contracts at thereporting date, although that is not our intent.

The unrealized, mark-to-market gains for the threemonth period ended June 30, 2007 are the result of a decline in the forward anddaily prices of natural gas and NGLs from March 31, 2007.  The unrealized mark-to-market losses for thesix month periods ended June 30, 2007, are the result of increases in theforward and daily market prices of natural gas and NGLs from December 31,2006.  The changes in fair value of ourportfolio of commodity-based derivative financial instruments that do notqualify for hedge accounting are a result of the volatility in the underlyingprices for natural gas, NGLs and crude oil. For the three and six month periods ended June 30, 2006, decliningforward and daily prices of natural gas and NGLs produced unrealized,mark-to-market gains in our portfolio of commodity derivative financialinstruments. While the natural gas and NGL pricing environment continues toremain volatile, the mark-to-market gains and losses created by thisvolatility do not affect our cash flow. We expect these non-cash gainsand losses to be offset in future quarters as we settle the derivativefinancial instruments and the underlying physical transactions.

Thefollowing table presents the unrealized, non-cash, mark-to-market gains andlosses by segment, associated with our derivative financial instruments:

| ** **                            | ** ** | **Three months ended  June 30,** | ** ** | **Six months ended  June 30,** | ** ** |
|---------------------------------------|------------|-------------------------------------------------|------------|-----------------------------------------------|------------|
| ** **                            | ** ** | **  2007  **                | ** ** | **  2006  **              | ** ** | **2007** | ** ** | **2006** | ** ** |
| ** **                            | ** ** | **(unaudited, in millions)**          | ** ** |
| Natural Gas  segment                  |       |                                            |       |                                          |       |   |   |   |   |   |   |   |   |
| Ineffectiveness                       |       |                                            | $          | 0.2                                           |       |   |   | $ | (0.1 | ) |   | $ | 0.3 |   | $ | (0.1 | ) |
| Non-qualified hedges                  |       |                                            | (2.8       | )                                             |       |   | (3.6 | ) |   | (6.0 | ) | (1.8 | ) |
| Marketing                             |       |                                            |       |                                          |       |   |   |   |   |   |   |   |   |
| Non-qualified hedges                  |       |                                            | 6.3        |                                          |       |   | 5.4 |   |   | (6.9 | ) | 31.3 |   |
| Derivative fair value  gains (losses) |       |                                            | $          | 3.7                                           |       |   |   | $ | 1.7 |   |   | $ | (12.6 | ) | $ | 29.4 |   |

 

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**RESULTS OFOPERATIONS—BY SEGMENT**

***Liquids***

Thefollowing tables set forth the operating results and statistics of our Liquidssegment assets for the periods presented:

| ** **                                         | ** ** | **Three months ended  June 30,** | ** ** | **Six months ended  June 30,** | ** ** |
|----------------------------------------------------|------------|-------------------------------------------------|------------|-----------------------------------------------|------------|
| ** **                                         | ** ** | **   2007   **    | ** ** | **   2006   **  | ** ** | **2007** | ** ** | **2006** | ** ** |
| ** **                                         | ** ** | **(unaudited, in millions)**          | ** ** |
| **Operating  Results**                             | ** ** |                                            | ** ** | ** **                                    |       |   | ** ** | ** ** |   | ** ** | ** ** | ** ** | ** ** |
| Operating revenues                                 |       |                                            | $          | 129.4                                         | ** ** |   |   | $ | 124.9 | ** ** |   | $ | 262.2 |   | $ | 247.5 |   |
| Operating and administrative                       |       |                                            | 40.6       | ** **                                    |       |   | 35.1 | ** ** |   | 74.3 |   | 63.7 |   |
| Power                                              |       |                                            | 27.3       | ** **                                    |       |   | 24.2 | ** ** |   | 57.4 |   | 50.5 |   |
| Depreciation and amortization                      |       |                                            | 16.7       | ** **                                    |       |   | 15.9 | ** ** |   | 33.1 |   | 31.8 |   |
| Operating expenses                                 |       |                                            | 84.6       | ** **                                    |       |   | 75.2 | ** ** |   | 164.8 |   | 146.0 |   |
| **Operating  Income**                              |       |                                            | $          | 44.8                                          | ** ** |   |   | $ | 49.7 | ** ** |   | $ | 97.4 |   | $ | 101.5 |   |
| **Operating Statistics**                           | ** ** |                                            | ** ** | ** **                                    |       |   | ** ** | ** ** |   | ** ** | ** ** | ** ** | ** ** |
| **Lakehead  system:**                              | ** ** |                                            | ** ** | ** **                                    |       |   | ** ** | ** ** |   | ** ** | ** ** | ** ** | ** ** |
| United States(1)                                   |       |                                            | 1,138      | ** **                                    |       |   | 1,186 | ** ** |   | 1,192 |   | 1,173 |   |
| Province of Ontario(1)                             |       |                                            | 340        | ** **                                    |       |   | 296 | ** ** |   | 338 |   | 322 |   |
| **Total Lakehead system deliveries****(1)**        |       |                                            | 1,478      | ** **                                    |       |   | 1,482 | ** ** |   | 1,530 |   | 1,495 |   |
| **Barrel miles (billions)**                        |       |                                            | 97         | ** **                                    |       |   | 94 | ** ** |   | 200 |   | 194 |   |
| **Average haul (miles)**                           |       |                                            | 722        | ** **                                    |       |   | 699 | ** ** |   | 722 |   | 719 |   |
| **Mid-Continent  system deliveries****(1)**        |       |                                            | 248        | ** **                                    |       |   | 260 | ** ** |   | 245 |   | 248 |   |
| **North  Dakota system:**                          | ** ** |                                            | ** ** | ** **                                    |       |   | ** ** | ** ** |   | ** ** | ** ** | ** ** | ** ** |
| Trunkline                                          |       |                                            | 92         | ** **                                    |       |   | 86 | ** ** |   | 89 |   | 84 |   |
| Gathering                                          |       |                                            | 6          | ** **                                    |       |   | 6 | ** ** |   | 6 |   | 7 |   |
| **Total North Dakota system deliveries****(1)**    |       |                                            | 98         | ** **                                    |       |   | 92 | ** ** |   | 95 |   | 91 |   |
| **Total Liquids Segment Delivery  Volumes****(1)** |       |                                            | 1,824      | ** **                                    |       |   | 1,834 | ** ** |   | 1,870 |   | 1,834 |   |

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(1)                Averagebarrels per day (“Bpd”) in thousands.

***Three months ended June 30, 2007 compared withthree months ended June 30, 2006***

Our Liquids segment accounted for $44.8 million ofoperating income during the three months ended June 30, 2007, a decreaseof $4.9 million from the $49.7 million generated during the same period in2006. Although the operating revenues of our Liquids business for the secondquarter of 2007 were greater than the comparable period of 2006, they were morethan offset by increases in operating expenses primarily associated with ourpipeline integrity management program and power usage.

Operating revenue for the three months ended June 30,2007 increased by approximately $4.5 million to $129.4 million from $124.9million for the same period in 2006. The increase in revenue is predominantlythe result of the increase in average tariffs on all three of our Liquidssystems associated with the annual index rate increase that went into effect July 1,2006. Additionally, new tariff rates went into effect April 1, 2007, onour Lakehead system to reflect the annual calculation of the SEP II and othersurcharges based on true-ups of prior year amounts and estimates for 2007, aswell as an adjustment for the Terrace surcharge due to lower than expectedvolumes moving on the Lakehead system in 2006. These combined tariff increasesand longer hauls contributed an additional $3.5 million to our revenues for thethree months ended June 30, 2007. Also contributing to the increase inrevenues for the three months 

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ended June 30, 2007,was an increase in contract storage fees generated by our Cushing terminal fromthe additional storage tanks we placed in service in late 2006.

Delivery volumes on our Liquids systems declined from1.834 million Bpd during the three months ended June 30, 2006 to 1.824million Bpd during the same period in 2007. The reduction of delivery volumeson our Lakehead system are primarily due to scheduled and unscheduledmaintenance performed by producers on their upgrader facilities and, to alesser extent, downstream refinery outages in the Midwest United States. Weexpect the decline in delivery volumes on our Lakehead system to reverse duringthe second half of 2007 when the maintenance activities being performed by ourupstream and downstream customers are expected to be complete. OurMid-Continent system continues to operate near capacity, although throughputhas declined to accommodate the transportation of more heavy crude. Partiallyoffsetting the lower volumes on our Lakehead and Mid-Continent systems is thevolume growth on our North Dakota system resulting from completion of ourhydrostatic testing program in the third quarter of 2006, which allowed us toincrease the capacity of the system.

Operating and administrative expenses for the Liquidssegment increased $5.5 million for the three months ended June 30, 2007,compared with the same period in 2006. The increase is driven primarily byhigher costs we incurred in connection with our pipeline integrity managementprogram and to a lesser extent by higher oil measurement losses and byworkforce related costs associated with the operational, administrative,regulatory and compliance support services necessary for our systems. Alsocontributing to the increase in operating costs are property taxes, which werelower in 2006 due to favorable settlements of prior year property taxassessments that we realized in that year.

Power costs increased $3.1million to $27.3 million in the second quarter of 2007, compared with $24.2million for the same period in 2006, primarily due to the higher utility rateswe are charged by our power suppliers.

***Six months ended June 30, 2007 compared with sixmonths ended June 30, 2006***

Our Liquids segmentaccounted for $97.4 million of operating income during the six monthsended June 30, 2007, representing a $4.1 million decrease over the $101.5million for the same period in 2006. The components comprising our operating income changed during the six monthsended June 30, 2007 compared with the six months ended June 30, 2006,primarily for the same reasons as noted above in the three-month analysis. Inaddition, however, operating revenues also increased as a result of increaseddelivery volumes during the first six months of 2007 over the comparable periodof 2006, due to upgrader expansions that were completed in the second half of2006. These additional delivery volumes in the first six months of 2007 alsocontributed to additional power costs in relation to the first six months of2006.

*Future ProspectsUpdate for Liquids*

We and Enbridge areactively working with our customers to develop transportation options that willallow Canadian crude oil greater access to markets throughout the UnitedStates.

*Partnership Projects*

*Southern Access*

In conjunction with Enbridge, we continue to progresson schedule with construction of the 400,000 Bpd Southern Access expansionproject. We are undertaking the United States portion of the expansion on ourLakehead system. The first stage of construction, which is on schedule forcompletion in early 2008, will add approximately 44,000 Bpd of capacity in 2007and up to an additional 146,000 Bpd by early 2008. This stage of the projectincludes a new pipeline between Superior and Delavan, Wisconsin, along withpump station enhancements upstream and downstream of this segment.

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The second stage of the expansion project will provideadditional upstream pumping capacity and a new pipeline from Delavan toFlanagan, Illinois, with completion expected in early 2009. Completion of thetotal Southern Access expansion project will create a 454-mile pipelinewith approximately 400,000 Bpd of incremental capacity on our Lakehead system. InApril 2007, the Illinois Commerce Commission approved and allowed theproject to exercise the right of eminent domain if necessary to securerights-of-way for the project.

As a result of theescalation of costs we have experienced with the first stage of the project forlabor, materials and rights-of-way, we are revising our estimated cost tocomplete the project. We anticipate the ultimate cost to complete our portionof this project to approximate $1.8 billion. The risk to our unitholdersresulting from the escalation of costs is largely mitigated by the cost ofservice tolling arrangement used for this project. Approximately 88 percent ofthe cost overage will be included in the rate base, which forms the basis fordetermining our tariff rates for transportation. The remaining 12 percent ofthe project cost relates to installing larger pipe than required under currentagreements which we are financing in anticipation of future expansionopportunities.

*Alberta Clipper*

Based on forecasts of oil sands production growthdeveloped by Enbridge, as well as forecasts by the Canadian Association ofPetroleum Producers, or CAPP, we believe that there will be a need foradditional export pipeline capacity out of Western Canada over and aboveprojects currently under development. As a result of this analysis and supportreceived from shippers, we and Enbridge are planning to develop the AlbertaClipper project. This project will involve construction of a new 36-inchdiameter, 1,000 mile heavy crude oil pipeline from Hardisty, Alberta toSuperior generally within or adjacent to our and Enbridge’s existingrights-of-way. We will construct approximately 330 miles of the new pipelinefrom the International Border near Neche, North Dakota to Superior. AlbertaClipper will have an initial capacity of 450,000 Bpd and allows for expansionsup to 800,000 Bpd by adding pump stations. In addition, complementary capacityon the Southern Access 42-inch pipeline from Superior to Flanagan will beobtained by installing additional pump stations. We anticipate that our shareof the construction cost for the United States segment of the project willapproximate $1.0 billion, in 2007 dollars, excluding capitalized interest. AlbertaClipper is expected to be in service by mid-2010.

In May 2007, Enbridgefiled an application with Canada’s National Energy Board, or NEB, for theconstruction and operation of the Canadian segment of the project. In June 2007Enbridge filed supplements to this application setting forth the tollingprinciples for the Canadian portion of the project, which are supported by CAPP.We plan to file a similar set of toll principles with the Federal EnergyRegulatory Commission (“FERC”). The project remains subject to regulatoryapprovals and receipt of various permits in Canada and the United States. Enbridgeis progressing with land access, engineering and initial procurementcommitments to facilitate commencement of project construction.

*North Dakota*

Work continues to progress for a fourth quarter 2007completion of our previously announced North Dakota system expansion. NorthDakota Public Service Commission approvals have been obtained for all phases ofthe project which will add approximately 30,000 Bpd of mainline throughputcapacity and expand the system’s feeder segment by approximately 30,000 Bpd atan estimated cost of $0.1 billion.

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Regional producers in theWilliston basin areas of Montana and North Dakota have continued to expressinterest in further expansion of pipeline capacity on the North Dakota system. Asa result, we initiated a binding “Open Season” in June 2007 for 10-yearcapacity commitments for our proposed Phase 6 expansion project. Theproposed $0.13 billion Phase 6 expansion, if fully subscribed, would increasesystem capacity to 155,000 Bpd, from the 110,000 Bpd of capacity we expect willbe available by year-end 2007. Should interest for incremental capacity on theNorth Dakota system exceed the available firm capacity offered through the OpenSeason, we will work with shippers to plan for further expansion of the systemcapacity. The “Open Season” will end at noon August 3, 2007, followingwhich we will evaluate whether to proceed with this proposed expansion project.

*Superior andGriffith Storage*

Due to forecastedproduction increases of synthetic heavy crude oil that we anticipate will betransported on the Enbridge/Lakehead mainline systems from Western Canada toChicago, Illinois we are constructing additional crude oil storage tanks atSuperior and Griffith to accommodate the anticipated volumes. We are buildingtwo tanks with an approximate capacity of 360,000 barrels each that arescheduled for completion in the second half of 2007 and two additional tankseach with an approximate capacity of 250,000 barrels each to be completedduring 2008.

*Mid-ContinentTerminal Storage*

We continue to experiencestrong interest from customers in securing access to long-term contract storagecapacity at our Cushing, Oklahoma terminal. During 2006, we obtainedcommitments and initiated construction of an additional 5.0 million barrels ofstorage tanks, 1.1 million barrels of which were completed in late December 2006.During the first half of 2007 we have completed construction of threeadditional storage tanks with approximately 1.1 million barrels of capacity.The remaining 2.8 million barrels of capacity will be completed during 2007 atan expected cost of $53 million. Once complete our total Mid-Continent terminalcapacity will be approximately 16.7 million barrels, which includes 1.4 millionbarrels of operational storage. This capacity will increase operational tankageavailable to support our Mid-Continent liquids pipeline systems, and availablecontract storage.

*Enbridge and Other Projects*

*Spearhead Pipeline*

In another effort toprovide shippers access to new markets, Enbridge acquired a pipeline that runsfrom Chicago to Cushing. The pipeline, renamed Spearhead, began deliveringCanadian crude oil to the major oil hub at Cushing in March 2006 and hasoperated at or near its capacity of 125,000 Bpd. We have benefited from WesternCanadian crude oil being carried on our Lakehead system as far as Chicago, andthen transferred to the Spearhead pipeline. On March 2, 2007, Enbridgeinitiated a binding open season for expansion of the pipeline to 190,000 Bpd,which was successfully concluded in late April with receipt of bindingcommitments for capacity in excess of 30,000 Bpd. This project will becomplementary to our Lakehead system and Enbridge is targeting completion inearly 2009.

*Southern AccessExtension*

In July 2006,Enbridge announced that it received support from shippers and CAPP for its 36-inchdiameter Southern Access Extension pipeline from Flanagan, Illinois to Patoka,Illinois. The extension will broaden the reach of the Enbridge/Lakeheadmainline system to incremental markets accessible from the Patoka hub. Theproject is scheduled for completion in the first quarter of 2009 and will beundertaken by Enbridge; however, we will benefit through incremental volumesmoving through our Lakehead system to 

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reachthis extension. Enbridge expects to file a petition for declaratory order withthe FERC in August 2007 to address tolling matters and should allow theproject to proceed on schedule.

*Southern Lights*

Following completion of a successful open season in2006, Enbridge initiated its Southern Lights project to construct a diluentpipeline from Chicago, Illinois to Edmonton, Alberta to meet the growing demandfor crude oil diluent required to transport the heavy oil and bitumen (a thick,tar-like form of oil) being produced in increasing volumes from the Alberta oilsands. The project involves the exchange of a 156-mile section ofpipeline we own for a similar section of a new pipeline to be constructed aspart of the project. In addition, this project involves a reconfiguration ofour light crude mainline system which will provide an additional 45,000 Bpd ofeffective capacity at no cost to us. We expect to benefit from increased heavycrude shipments, which will be facilitated by the diluent line.

This project is expectedto be in service during 2010. Enbridge has filed applications with the NEB forapproval of all facets of the Canadian portion of the project and the majorityof necessary applications for the United States portion of the project withUnited States federal and state regulatory agencies. Enbridge expects to file aFERC petition for declaratory order with respect to tolling matters in the nearfuture. In conjunction with the Southern Access project, the Southern Lightsproject has been allowed the right to exercise eminent domain for right of wayin Illinois. Early construction and right-of-way acquisition related to thisproject continues in tandem with stage one of the Southern Access project.

*United States GulfCoast Access*

In June 2007,Enbridge and ExxonMobil Pipeline Company announced they are jointly assessingthe possibility of building a crude oil pipeline from Patoka, Illinois toBeaumont, Texas and through to Houston. This pipeline project is in the initialstages, and Enbridge and ExxonMobil are in discussions with potential shippersregarding the scope, timing, and value of the project. Construction of thisproject would complement our Lakehead system and further support its expansion.

*Eastern PADD IIAccess*

Enbridge has held discussions with several refiners inthe eastern United States to gauge interest in supporting the development of apipeline to provide incremental pipeline capacity to this market. A project ofthis nature would be complementary to our Lakehead system.

We and Enbridge believethat the Southern Access Expansion Program, the Alberta Clipper Project, andother initiatives to provide access to new markets in the Midwest,Mid-continent and Gulf Coast, offer flexible solutions to future transportationrequirements of western Canadian crude oil producers, and the in-service timingof these solutions is in line with prospective shipper needs.

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***Natural Gas***

Thefollowing tables set forth the operating results of our Natural Gas segmentassets and approximate average daily volumes of our major systems in millionsof British Thermal units per day, or MMBtu/d, of natural gas for the periodspresented:

| ** **                          | ** ** | **Three months ended  June 30,** | ** ** | **Six months ended  June 30,** | ** ** |
|-------------------------------------|------------|-------------------------------------------------|------------|-----------------------------------------------|------------|
| ** **                          | ** ** | **2007**                                        | ** ** | **2006**                                      | ** ** | **2007** | ** ** | **2006** | ** ** |
| ** **                          | ** ** | **(unaudited, in millions)**          | ** ** |
| **Operating Results**               | ** ** | ** **                                      | ** ** | ** **                                    | ** ** | ** ** | ** ** | ** ** | ** ** |
| Operating  revenues                 |       | $                                               | 714.3      |                                          | $          | 673.5 |   | $ | 1,469.8 |   | $ | 1,544.5 |   |
| Cost of natural  gas                |       | 591.8                                           |       | 566.9                                         |       | 1,255.0 |   | 1,340.4 |   |
| Operating and  administrative       |       | 60.9                                            |       | 50.0                                          |       | 122.2 |   | 93.7 |   |
| Depreciation and  amortization      |       | 22.4                                            |       | 17.9                                          |       | 42.4 |   | 34.5 |   |
| Operating  expenses                 |       | 675.1                                           |       | 634.8                                         |       | 1,419.6 |   | 1,468.6 |   |
| **Operating  Income**               |       | $                                               | 39.2       |                                          | $          | 38.7 |   | $ | 50.2 |   | $ | 75.9 |   |
| **Operating  Statistics (MMBtu/d)** | ** ** | ** **                                      | ** ** | ** **                                    | ** ** | ** ** | ** ** | ** ** | ** ** |
| East Texas                          |       | 1,190,000                                       |       | 1,012,000                                     |       | 1,162,000 |   | 966,000 |   |
| Anadarko                            |       | 588,000                                         |       | 568,000                                       |       | 585,000 |   | 565,000 |   |
| North Texas                         |       | 352,000                                         |       | 283,000                                       |       | 336,000 |   | 281,000 |   |
| UTOS                                |       | 191,000                                         |       | 188,000                                       |       | 158,000 |   | 193,000 |   |
| MidLa                               |       | 131,000                                         |       | 131,000                                       |       | 120,000 |   | 107,000 |   |
| AlaTenn                             |       | 33,000                                          |       | 34,000                                        |       | 46,000 |   | 44,000 |   |
| KPC                                 |       | 26,000                                          |       | 27,000                                        |       | 32,000 |   | 37,000 |   |
| Bamagas                             |       | 114,000                                         |       | 83,000                                        |       | 115,000 |   | 60,000 |   |
| Other major  intrastates(1)         |       | 251,000                                         |       | 217,000                                       |       | 259,000 |   | 218,000 |   |
| Total                               |       | 2,876,000                                       |       | 2,543,000                                     |       | 2,813,000 |   | 2,471,000 |   |

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(1)                We have includedin Other major intrastates the volumes of our Gloria system for the three andsix month periods ended June 30, 2007 and 2006, in the amounts of  63,000 MMBtu/d, 64,000 MMBtu/d, 64,000MMBtu/d and 63,000 MMBtu/d, respectively.

***Three months ended June 30, 2007 compared withthree months ended June 30, 2006***

Our Natural Gas segment contributed $39.2 million ofoperating income for the three months ended June 30, 2007, an increase of$0.5 million from the $38.7 million contributed in the corresponding period of2006. Our revenues improved over the same period last year primarily due togreater volumes gathered and processed in connection with additional capacityfrom projects coming on-line during the quarter and increased drilling activityin the areas served by our natural gas assets.

Average dailyvolumes on our major natural gas systems increased approximately 13 percent inthe second quarter of 2007, compared with the corresponding period in 2006. Theincreased volumes for 2007 continue to reflect our ongoing investments tofurther expand the capacity of our systems and services. The following projectscompleted during 2006 and 2007 contributed to the increase in the average dailyvolumes and operating results on our major natural gas systems:

·       Completionof Phase I of our East Texas Expansion and Extension project (Project Clarity)which includes the Marquez treating plant with additional capacity of 200 millioncubic feet per day, or MMcf/d, of natural gas and additional pipeline capacityto the existing southeast section of this area;

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·       Expansionof our existing 275 MMcf/d Aker treating facility with construction of apipeline adjoined to our Marquez treating plant to increase our treating capacity;

·       Constructionof our Hidetown processing facility on our Anadarko system was commissioned atthe end of April 2007 and was operating at expected levels by the end of May 2007,with capacity of 120 MMcf/d;

·       Constructionof our 120 MMcf/d Henderson natural gas processing facility on our East Texassystem was completed at the end of the third quarter of 2006 and processedincremental volumes of approximately 116 MMcf/d; and

·       Alink between our North Texas and East Texas systems became fully operationalduring the third quarter of 2006, increasing the utilization of our 500 MMcf/dEast Texas intrastate pipeline that we placed in service in June 2005;

In addition to the investments we have made to expandthe volumes in areas served by our natural gas assets, the volume and revenuegrowth is also the result of additional wellhead supply contracts and robustdrilling activity in the Anadarko basin, Bossier Trend and Barnett Shale. Weexpect increasing volumes on our major natural gas systems to result from ourcontinuing investments to expand the capacity of our systems.

Although the average daily volumes of our natural gassystems for the three months ended June 30, 2007 were greater than sameperiod of 2006, operating income of our Natural Gas business was negativelyaffected by lower processing revenue less the cost of natural gas purchased forprocessing, which we refer to as processing margin.  A variable element of our Natural Gas segment’soperating income is derived from processing of natural gas under keep-wholearrangements. Operating income derived from our keep-whole processing forthe three months ended June 30, 2007 decreased to approximately $13.5*** ***million from$17.4 million for the same period in 2006. Circumstances in the secondquarter of 2006, resulting from instability in the crude oil market created anoperating environment where NGL prices, which tend to move in correlation withcrude oil prices, were trending higher while natural gas prices were declining.As a result, although processing margins in the second quarter of 2007 werefavorable, they were not as favorable as in the same period of 2006.

Our processing margin was also reduced byapproximately $2.5 million in the second quarter of 2007 due to the carryovereffect of operational problems we identified with our Zybach processingfacility in the first quarter of 2007. In April 2007, we undertook aproject to repair and modify our Zybach processing plant to increase its NGLrecoveries, which had decreased in the first quarter of 2007 compared to thelevel of production when we initially commissioned the plant in 2006. Wecompleted the necessary repairs and modifications during April 2007 andthe plant recovered NGLs at expected levels throughout May and June of2007.

A portion of our Natural Gas segment is exposed tocommodity price risks associated with the percentage of proceeds, percentage ofliquids, and percentage of index contracts that we negotiate with producers.Under the terms of these contracts, we retain a portion of the natural gas andNGLs we process in exchange for providing these producers with our services. Inorder to protect our unitholders from the volatility in cash flows that canresult from fluctuations in commodity prices, we enter into derivativefinancial instruments to fix the sales price of the natural gas and NGLs weanticipate receiving under the terms of these contracts. We targetapproximately 70 to 80 percent hedge coverage of our anticipated near-termexposure to commodity prices using derivative financial instruments. As aresult of entering into these derivative financial instruments, we have largelyfixed the amount of cash that we will pay for natural gas and receive in thefuture when we sell the processed natural gas and NGLs, although the marketprice of these commodities will continue to fluctuate during that time. Anothersignificant portion of the revenue 

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we receive is derived fromfees charged for gathering and treating of natural gas volumes and otherrelated services which are not directly dependent on commodity prices.

Operating income of our Natural Gas segment for thethree months ended June 30, 2007 includes unrealized non-cash,mark-to-market net losses of $2.6 million, including $0.2 million of gainsresulting from ineffectiveness of our cash flow hedges and $2.8 million oflosses derived from our derivative financial instruments that do not qualifyfor hedge accounting treatment under SFAS No. 133. In the three monthsended June 30, 2006, our operating income was decreased by unrealized non-cash,mark-to-market net losses of $3.7 million, including $0.1 million of lossesresulting from ineffectiveness of our cash flow hedges and $3.6 million oflosses derived from our derivative financial instruments that do not qualifyfor hedge accounting treatment under SFAS No. 133. We expect the netmark-to-market gains and losses to be offset when the related physicaltransactions are settled (refer also to the discussions included in Note 10 ofItem 1. Financial Statements and following under Derivative Activities, andItem 3. Quantitative and Qualitative Disclosures About Market Risk).

Operating and administrative costs of our Natural Gassegment were $10.9 million greater for the three months ended June 30,2007 than the three months ended June 30, 2006, primarily as a result of $6.1million in increased workforce related costs associated with the expansion ofour systems, maintenance activities and other costs that are mostly variablewith volumes. In addition, repairs and maintenance costs increased by $1.9million, including costs related to compressor maintenance, downtime forroutine and unscheduled maintenance, $0.6 million of pipeline integrity costsand other similar items that have increased with the expansion of our existingnatural gas systems. Included in the costs related to repairs and maintenanceis $0.6 million of operating expenses associated with modifications made tocorrect the operating inefficiencies associated with our Zybach processingfacility.

Workforce related costs increased $6.1 million due tothe additional resources and related benefit costs we are charged for theoperational, administrative, regulatory and compliance support necessary forour existing assets and the expansion of our natural gas operations. Ourgeneral partner charges us the costs associated with employees and related benefits for personnel that are assigned to us orotherwise provide us with managerial and administrative services. The portionof compensation and related costs we are charged is dependent upon such itemsas estimated time spent, miles of pipe and headcount. In addition we haveexperienced an increase in outside contract labor cost, given the high demandand competitive rates within our industry as a result of continuous pipelineexpansions across the areas we serve.  We expect workforce related costs in additionto materials, supplies and other cost to continue increasing as we expand oursystems and increase the volumes of natural gas services we provide.

Depreciation expense forour Natural Gas segment was $4.5 million higher in the second quarter of 2007as compared to the second quarter of 2006, primarily as a result of capital projectscompleted and placed in-service during 2006. Additionally, we revised the depreciationrates for a portion of our FERC—regulated natural gas assets effective July 1,2006, to reflect a decrease in the remaining service life of these natural gasassets. We expect depreciation expense to increase throughout 2007 as wecomplete our construction projects and place the assets into service.

***Six months ended June 30, 2007 compared withsix  months ended June  30,2006***

Our Natural Gas segment produced $50.2 million ofoperating income for the six months ended June 30, 2007, a decrease of$25.7 million from the $75.9 million of operating income generated in thecorresponding period of 2006. Although the overall volumes for the first six months of 2007on our three largest systems were greater than the comparable period of 2006,operational inefficiencies at our Zybach plant and an unexpected increase inmeasurement losses, primarily on our East Texas and Anadarko systems reducedthe operating income of our Natural Gas segment.

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Average daily volumes on our major natural gas systemsincreased 14 percent, or approximately 342,000 MMBtu/d, for the six monthsended June 30, 2007, compared with the corresponding period of 2006, whichcontributed favorably to our operating income. The contribution to operatingincome resulting from the increase in average daily volumes was partiallyoffset by the lower processing margins we derived from our processing assetsduring the six months ended June 30, 2007 in relation to the same periodof 2006. Operating income derived from processing natural gas under keep-wholearrangements on our major systems decreased to approximately $19.0 million forthe six months ended June 30, 2007, compared with approximately$28 million for the corresponding period in 2006. Additionally, theoperational issues associated with our Zybach processing plant reduced ourprocessing margins by approximately $10.5 million from the amounts we realizedin the comparable period of 2006. The reasons for the changes in operatingincome are consistent with the discussion above in our three month analysis,with the exception of measurement losses which are discussed below.

Natural gas measurement losses occur as part of thenormal operating conditions associated with our natural gas pipelines. Thequantification and resolution of measurement losses is complicated by severalfactors including varying qualities of natural gas in the streams gathered andprocessed through our systems, changes in weather temperatures and variances inmeasurement that are inherent in metering technologies. During the firstquarter 2007, we identified operating conditions on our gathering systems whichwe believe have contributed to an increase in measurement losses. We have takensteps to install separator equipment to identify and eliminate free-water inthe natural gas streams, one of the underlying causes for the increase inmeasurement losses during the first quarter of 2007. During the first sixmonths of 2007, we estimate that measurement losses resulted in approximately$11 million of additional cost to our natural gas systems relative to the firstsix months of 2006.

Operating income of our Natural Gas segment for thesix months ended June 30, 2007 includes non-cash, mark-to-market netlosses of $5.7 million, including $0.3 million of gains due to hedgeineffectiveness and$6.0 million of losses derived from our derivative financial instruments thatdo not qualify for hedge accounting treatment under SFAS No. 133. Inthe six months ended June 30, 2006, our operating income was reduced by unrealized non-cash,mark-to-market net losses of $1.9 million, including $0.1 million of lossesresulting from ineffectiveness of our cash flow hedges and $1.8 million oflosses derived from our derivative financial instruments that do not qualifyfor hedge accounting treatment under SFAS No. 133. The non-cashmark-to-market net losses in 2007 are primarily derived from hedgeineffectiveness partially offset by gains from our derivative financialinstruments that do not qualify for hedge accounting treatment under SFAS No. 133as discussed above under our three-month analysis (refer also to thediscussions included in Note 10 of Item 1. Financial Statements, below underDerivative Activities, and Item 3. Quantitative and Qualitative DisclosuresAbout Market Risk).

Operating andadministrative costs associated with our Natural Gas segment were$28.5 million greater for the six months ended June 30, 2007, thanfor the corresponding period in 2006 for the same reasons discussed above inour three-month analysis.

*Future ProspectsUpdate for Natural Gas*

We continue to assess various expansion opportunitiesto pursue our strategy for growth. While we remain committed to makingaccretive acquisitions in or near areas where we already operate or have acompetitive advantage, we will continue to focus our efforts primarily ondevelopment of our existing pipeline systems. We may, and have, pursuedopportunities to divest any non-strategic natural gas assets as conditionswarrant.

Results of our natural gas gathering and processingbusiness depend upon the drilling activities of natural gas producers in theareas we serve. During the first half of 2007, increased drilling in the areaswhere our gathering systems are located has contributed to the growth ofvolumes on our systems. We 

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expect the growth trend inthese areas to continue in the future as evidenced by external productionforecasts and the strong rig counts and permitting in the areas served by oursystems.

Producer drilling plans inregional plays, in the areas served by our natural gas assets, are expected toresult in continued production growth. To accommodate this further growth, weinitiated construction on several projects to increase our gathering andtreating infrastructure and market access capability. These projects continueto progress and include:

*East Texas SystemExpansion and Extension (Project Clarity):*

·       Theexpansion and extension of our East Texas natural gas system, referred to asthe Clarity project, includes construction of a 36-inch diameterintrastate pipeline from Bethel, Texas to Orange County, Texas with capacity ofapproximately 700 MMcf/d. The new pipeline will provide service to a number ofmajor industrial companies in Southeast Texas and will cross a number ofinterstate pipelines. We continue to secure additional commitments for capacityon the pipeline. We have continued to experience cost pressures for labor,materials and rights-of-way, in addition to cost associated with constructiondelays due to inclement weather. Each of these factors have contributed to ourexpectation that the ultimate cost to complete construction of this projectwill approximate $635 million.

·       The first phase of ourClarity project was completed in late March 2007 and includes theconstruction of a 24-inch diameter intrastate pipeline that extendsapproximately 60 miles from Marquez, Texas to Crockett, Texas and a 36-inchdiameter pipeline that extends approximately 53 miles from Crockett toGoodrich, Texas. Completion of this phase has contributed modest operatingrevenue to our natural gas segment for the second quarter of 2007 followingcompletion of upstream gathering facilities late second quarter.

·       Theremainder of our Clarity project is expected to be completed in stagesthroughout 2007 and early 2008. These phases include the construction of a 36-inchdiameter intrastate pipeline that extends approximately 63 miles from Bethel toCrockett and approximately 42 miles from Goodrich to Kountze, Texas andapproximately 41 miles from Kountze to Orange County.

·       As part of our East Texasexpansion project we added a 200 MMcf/d treating facility near Marquez which isconnected to the 36-inch diameter intrastate pipeline via a new 24-inchdiameter pipeline. This project was completed in conjunction with the firstphase of our Clarity project in late March 2007 as mentioned above in ouroperating results, and is expected to contribute additional capacity and volumegrowth on our East Texas natural gas system through increased carbon dioxide(CO2) and sourgastreatingcapacity commensurate with the completion of several ongoing constructionprojects in the area.

*Other East TexasProjects:*

·       Theexpansion of our sour gas treating capacity on the East Texas system willincrease the total sulfur capacity in the first half of 2007 from 72.5 tons perday (tpd) to 125 tpd by early 2008, in order to handle additional sour gassupply and higher concentration levels of hydrogen sulfide (H2S).

·       Theinstallation of additional processing plants will enable our East Texas systemto meet the increasingly more stringent pipeline gas quality specifications bylate 2007.

*North Texas SystemProjects:*

·       Inorder to accommodate the active development and anticipated growth occurring inthe Barnett Shale play in North Texas we have commenced construction of two newgas processing plants totaling approximately 75 MMcf/d of capacity and relatedupstream facilities. These facilities, with 

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processingcapacities of 35 MMcf/d and 40 MMcf/d, are expected to become operational inthe second half of 2007.

*Anadarko SystemProjects:*

·       OurAnadarko system continues to experience considerable growth as a result of therapid development of the Granite Wash play in Hemphill and Wheeler counties inTexas. We commissioned our Hidetown and Hobart processing plants during thesecond quarter of 2007, increasing our processing capacity to 170 MMcf/d. Additionally,we continue to increase our field compression in the region. We anticipatethese facilities will contribute to our operating results in the second half of2007.

·       Duringthe second quarter of 2007, we refurbished our Zybach processing plant toaddress the operational inefficiencies being experienced by the plant. As aresult of the service and repairs, processing volumes have been restored toexpected levels.

When fully operational in late 2007, we expect thatthe new assets we are constructing will provide additional sources of cash flowfor us. We continue to evaluate otherprojects that could further integrate our major Texas-centered naturalgas pipeline systems.

A number of new interstatenatural gas transportation pipelines are being constructed that may alter thelandscape for interstate transportation of natural gas. Although a majority ofour Natural Gas segment revenues are derived from the gathering, processing andintrastate transportation of natural gas, these newly constructed pipelinescould affect the operating results of our existing market-based interstate andintrastate natural gas pipelines. Conversely, our supply based gatheringsystems may benefit from enhanced capacity out of our gathering areas.

*Other Matters*

In December 2005,Calpine Corporation (“Calpine”) and many of its subsidiaries, including thesubsidiary that owns the two utility plants served by our Bamagas system, filedvoluntarily petitions to restructure under Chapter 11 of the United StatesBankruptcy Code. Calpine has continued to perform under the terms of itsagreement with Bamagas. In June 2007, Calpine and certain of itssubsidiaries filed a Joint Plan of Reorganization and Disclosure Statement (the“Plan”) with the United States Bankruptcy Court. The Plan seeks to provide anequitable return to all stakeholders while providing for the long-termviability of Calpine. The Plan has not been approved by the United StatesBankruptcy Court and is subject to further negotiations with stakeholders. Thehearing date has not yet been set by the United States Bankruptcy Court forvoting purposes. Following the voting process, Calpine will ask the UnitedStates Bankruptcy Court to consider approval or “confirmation” of the Plan. Calpinelooks to have the Plan confirmed during the fourth quarter of 2007. We remainconfident that any losses we may incur with respect to Calpine’s bankruptcywill be minimal. We continue to monitor the Calpine bankruptcy proceedings andwill recognize any losses that may result when it becomes evident that a losshas been incurred.

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***Marketing***

Thefollowing table sets forth the operating results for the Marketing segmentassets for the periods presented:

| ** **                     | ** ** | **Three months  ended June 30,** | ** ** | **Six months  ended June 30,** | ** ** |
|--------------------------------|------------|--------------------------------------------|------------|------------------------------------------|------------|
| ** **                     | ** ** | **2007**                                   | ** ** | **2006**                                 | ** ** | **2007** | ** ** | **2006** | ** ** |
| ** **                     | ** ** | **(unaudited; in millions)**     | ** ** |
| Operating  revenues            |       | $                                          | 895.0      |                                     | $          | 626.3 |   | $ | 1,719.4 |   | $ | 1,521.3 |   |
| Cost of natural  gas           |       | 883.8                                      |       | 618.7                                    |       | 1,704.9 |   | 1,492.9 |   |
| Operating and  administrative  |       | 1.9                                        |       | 1.5                                      |       | 3.5 |   | 2.6 |   |
| Depreciation and  amortization |       | 0.7                                        |       | 0.1                                      |       | 0.8 |   | 0.2 |   |
| Expenses                       |       | 886.4                                      |       | 620.3                                    |       | 1,709.2 |   | 1,495.7 |   |
| **Operating Income (loss)**    |       | $                                          | 8.6        |                                     | $          | 6.0 |   | $ | 10.2 |   | $ | 25.6 |   |

 

***Three months ended June 30, 2007 compared withthree months ended June 30, 2006***

In the three months ended June 30, 2007, operatingincome from our Marketing segment increased $2.6 million to $8.6 million, from$6.0 million for the corresponding period in 2006. Included in operatingincome for the three months ended June 30, 2007 are unrealized, non-cash,mark-to-market gains of approximately $6.3 million compared with unrealized,non-cash, mark-to-market gains of $5.4 million for the comparable period in2006, associated with derivative financial instruments that do not qualify forhedge accounting treatment under SFAS No. 133. The unrealized, non-cash,mark-to-market gains for the three months ended June 30, 2007, are theresult of decreases in the forward and daily market prices of natural gas andNGLs from March 31, 2007. We expect these net mark-to-market gains to beoffset when the related physical transactions are settled (refer also to thediscussion included in Note 10 of Item 1. Financial Statements,following under Derivative Activities and Item 3. Quantitative andQualitative Disclosures About Market Risk).

Partially offsetting themark-to-market gains is a non-cash charge of $1.2 million we recorded to reducethe cost basis of our natural gas inventory to fair market value at June 30,2007. Natural gas prices as published by Platt’s *Gas Daily* for Henry Hub were approximately $6.80 per MMBtuat June 30, 2007, a decline from $7.34 per MMBtu at March 31, 2007. Asa result of this decline in the price of natural gas inventory at our storagelocations from March 31, 2007 to June 30, 2007, the weighted averagecost of our natural gas inventory at June 30, 2007 exceeded the marketprice of natural gas by approximately $1.2 million. Due to our hedging structures, weexpect that a majority of these charges will be offset by future financialtransactions that will settle at the time the natural gas inventory is sold. Weincurred a similar non-cash charge totaling $1.7 million for the three monthsended June 30, 2006.

***Six months ended June 30, 2007 compared withsix  months ended June 30, 2006***

In the first six months of 2007, the operating incomeof our Marketing segment decreased $15.4 million to $10.2 million, from$25.6 million for the corresponding period in 2006. Included in operatingincome for the first six months of 2007 are unrealized, non-cash,mark-to-market net losses of approximately $6.9 million associated withderivative financial instruments that do not qualify for hedge accountingtreatment under SFAS No. 133, as compared with unrealized mark-to-marketnet gains of $31.3 million for the comparable period in 2006. We expect thesenet mark-to-market losses to be offset when the related physical transactionsare settled (refer also to the discussion included in Note 10 ofItem 1. Financial Statements, following under Derivative Activities andItem 3. Quantitative and Qualitative Disclosures About Market Risk).

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The operating results of our Marketing business forthe first six months of 2007 also include gains of approximately $12 millionthat we realized upon the sale of natural gas inventory, includingapproximately $6 million of gains from the settlement of derivative financialinstrument hedging our natural gas inventory. Partially offsetting these gainsfor the six months ended June 30, 2007, are non-cash charges of $1.2million that we recorded to reduce the cost basis of our natural gas inventoryto fair market value. We recorded a similar non-cash charge of $9.7 millionduring the six months ended June 30, 2006. The market price for naturalgas in various storage locations may experience declines during the year fromthe prices at which the inventory was purchased. Due to our hedging structures,we expect that a majority of these charges will be offset by future financialtransactions that will settle at the time the natural gas inventory is sold.

A majority of the operating income of our Marketingsegment is derived from selling natural gas received from producers on ourNatural Gas segment pipeline assets to customers who need natural gas. Amajority of the natural gas we purchase is produced in Texas markets where we havelimited physical access to the primary interstate pipeline delivery points, orhubs such as Waha, Texas and the Houston Ship Channel. As a result, ourMarketing business must use third-party pipelines to transport the natural gasto these markets where it can be sold to our customers. However, physicalpipeline constraints often require our Marketing business to transport naturalgas to alternate market points. Under these circumstances, our Marketingsegment will sell the purchased gas at a pricing index that is different fromthe pricing index at which the gas was purchased. This creates a price exposurethat arises from the relative difference in natural gas prices between thecontracted index at which the natural gas is purchased and the index under whichit is sold, otherwise known as the “spread.” The spread can vary significantlydue to local supply and demand factors. Wherever possible, this pricingexposure is economically hedged using derivative financial instruments.However, the structure of these economic hedges often precludes our use ofhedge accounting under the requirements of SFAS No. 133, which can createvolatility in the operating results of our Marketing segment.

To ensure that we have access to primary pipelinedelivery points, we often enter into firm transportation agreements oninterstate and intrastate pipelines. To offset the demand charges associatedwith these firm transportation contracts, we look for market conditions thatallow us to lock in the price differential or spread between the pipelinereceipt point and pipeline delivery point. This allows our Marketing businessto lock in a fixed sales margin inclusive of pipeline demand charges. Weaccomplish this by transacting basis swaps between the index where the naturalgas is purchased and the index where the natural gas is sold. By transacting abasis swap between those two indices, we can effectively lock in a margin onthe combined natural gas purchase and the natural gas sale, mitigating thedemand charges on firm transportation agreements and limiting our exposure tocash flow volatility that could arise in markets where the firm transportationbecomes uneconomic. However, the structure of these transactions precludes ouruse of hedge accounting under the requirements of SFAS No. 133, which cancreate volatility in the operating results of our Marketing segment.

In addition to natural gas basis swaps, we contractfor storage to assist with balancing natural gas supply and end use marketsales. In order to mitigate the absolute price differential between the cost ofinjected natural gas and withdrawn natural gas, as well as storage fees, theinjection and withdrawal price differential, or “spread,” is hedged by buyingfixed price swaps for the forecasted injection periods and selling fixed priceswaps for the forecasted withdrawal periods. When the injection and withdrawalspread increases or decreases in value as a result of market price movements,we can earn additional profit through the optimization of those hedges in boththe forward and daily markets. Although each of these hedge strategies aresound economic hedging techniques, these types of financial transactions do notqualify for hedge accounting under the SFAS No. 133 guidelines. As such,the non-qualified hedges are accounted for on a mark-to-marketbasis, and the periodic change in their market value, although non-cash, willimpact the income statement.

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***Corporate***

Interest expense was $21.5 million and $46.8 millionfor the three and six month periods ended June 30, 2007, compared with$27.6 million and $55.5 million for the corresponding periods in 2006. Thedecrease is primarily the result of $10.4 million and $18.9 million of interestcapitalized on our construction projects for the three and six month periodsended June 30, 2007, compared with the $3.0 million and $3.4 millioncapitalized during the same periods of 2006. Partially offsetting the increasein capitalized interest is the additional interest expense generated by higherweighted average debt balances. Our weighted average rates of interest wereapproximately 5.96% and 5.92% during the three and six month periods ended June 30,2007, respectively, compared with approximately 5.86% and 5.87% during thecorresponding periods in 2006.

We are not a taxable entity for United States federalincome tax purposes or for the majority of states that impose an income tax. Ourincome tax expense of $1.3 million and $2.4 million for the three and six monthperiods ended June 30, 2007 results from the enactment, by the State ofTexas, of a new state tax computed on our 2007 modified gross margin. Nocomparable tax existed during 2006. We determined this tax to be an income taxunder the provisions of SFAS No. 109, *Accountingfor Income Taxes*. We computed our income tax expense for the quarterended June 30, 2007 by applying a 0.56% apportioned state income tax rateto taxable margin, as defined in State of Texas statutes. Our income taxexpense represents a 2.2% effective rate as applied to pretax book income.

In July 2007, theState of Michigan enacted substantial changes to its tax structure effective in2008 by imposing a new tax system on our operations. The new system iscomprised of two parts, a modified gross receipts tax at 0.8% and a 4.95% taxon income that will be levied on our Michigan operating activities. We expectto account for the impact of the income tax under SFAS No. 109, Accountingfor Income Taxes in the third quarter of 2007. We anticipate the effect of thistax legislation will be to increase our income tax expense for 2007 byapproximately $1.0 million.

**LIQUIDITY ANDCAPITAL RESOURCES**

***General***

We believe that our ability to generate cash flow, inaddition to our access to capital, is sufficient to meet the demands of ourcurrent and future operating and investment needs. Our primary cashrequirements consist of normal operating expenses, capital expenditures for ourexpansion projects, maintenance capital expenditures, debt service payments,distributions to our partners, acquisitions of new assets and businesses, andpayments associated with our derivative transactions. Short-term cashrequirements, such as operating expenses, maintenance capital expenditures debtservice payments and quarterly distributions to our partners, are expected tobe funded by our operating cash flows. Margin requirements associated with ourderivative transactions are generally supported by letters of credit issuedunder our Credit Facility. We expect to fund long-term cash requirementsfor expansion projects and acquisitions from several sources, including cashflows from our operating activities, borrowings under our commercial paperprogram or Credit Facility, and the issuance of additional debt and equitysecurities. Our ability to complete future offerings of our debt and equitysecurities and the timing of any such offerings will depend on various factors,including prevailing market conditions, interest rates, our financial conditionand credit rating at the time.

Our current businessstrategy emphasizes developing and expanding our existing Liquids and NaturalGas businesses with less focus on acquisitions. The internal growth projects wehave planned for our Natural Gas business (see Natural Gas segment—FutureProspects), coupled with the Southern Access and Alberta Clipper projects onour Lakehead system (see Liquids segment—Future Prospects), will requiresignificant expenditures of capital over the next several years. We expect tofund these expenditures from a balanced combination of additional issuances ofequity, in the form of limited 

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partnershipinterests, and long-term debt. Our planned internal growth projects willrequire us to bear the cost of constructing these assets before we will beginto realize a return on them in the form of additional cash flows. During ourconstruction of these major projects, our ability to increase distributionswhile funding these construction costs is likely to be limited.

***Capital Resources***

**Equity Capital**

Execution of our growth strategy and completion of ourplanned construction projects contemplate our accessing the public and privateequity markets to obtain the capital necessary to fund these projects. Duringthe first half of 2007, we generated $628.8 million of cash through equityissuances in both public and private transactions, including contributions ofapproximately $12.5 million from our general partner to maintain its twopercent general partner interest. We used the proceeds from these offerings partially to reduceoutstanding commercial paper we previously issued to finance a portion of ourcapital expansion projects,and invested the remaining amount in short-term commercial paper for use infuture periods to fund additional expenditures under our capital expansionprograms.

Thefollowing table provides additional information about these offerings:

| Issuance Date | ** ** | **Class of  Limited  Partnership  Interest**                   | ** **   | **Number of  Units  Issued** | ** ** | **Offering Price  per Unit** | ** ** | **Net Proceeds to  the Partnership** | ** ** | **General  Partner  Contribution** | ** ** | **Net Proceeds  Including  General Partner  Contribution** | ** ** |
|--------------------|------------|---------------------------------------------------------------------|--------------|-----------------------------------|------------|----------------------------------------|------------|-----------------------------------------------------|------------|------------------------------------|------------|----------------------------------------------------------------------|------------|
| ** **         | ** ** | **(in millions, except per unit amounts)** | ** **   |
| May 2007      |       |                                                                | Class A |                              |       |                                   | 5.300      |                                                |       |                               | $          | 58.00                                                                |       |   |   | $ | 301.9 |   |   |   | $ | 6.1 |   |   |   | $ | 308.0 |   |   |
| April 2007    |       |                                                                | Class C |                              |       |                                   | 5.931      |                                                |       |                               | $          | 53.11                                                                |       |   |   | 314.4 |   |   |   | 6.4 |   |   |   | 320.8 |   |   |
| Total              |       |                                                                |         |                              |       |                                   | 11.231     |                                                |       |                               |       |                                                                 |       |   | $ | 616.3 |   |   |   | $ | 12.5 |   |   |   | $ | 628.8 |   |   |

 

**Available Credit**

A significant source ofour liquidity is provided by the commercial paper market and our CreditFacility. We have a $600 million commercial paper program that is supported byour long-term Credit Facility, which we access primarily to provide temporaryfinancing for our operating activities, capital expenditures and acquisitions,at rates that are generally lower than the rates available under our CreditFacility.

*Credit Facility*

The amounts we may borrow under the terms of ourCredit Facility are reduced by the principal amount of our commercial paperissuances and the balance of our letters of credit outstanding. At June 30,2007, no amounts had been borrowed against our Credit Facility and we hadapproximately $90.0 million of letters of credit outstanding. At June 30,2007, we could borrow $765.0 million under the terms of our Credit Facilitywithout consideration to additional borrowings under our commercial paperprogram.

On April 4, 2007 weentered into the Second Amended and Restated Credit Agreement (Credit Facility)which among other things: (i) increases the maximum principal amount ofcredit available at any one time to us from $1 billion to $1.25 billion; (ii) givesus the right to request increases in the maximum principal amount of creditavailable at any one time to us up to $1.5 billion; (iii) eliminates thesublimit on letters of credit; (iv) provides for a five-year facility thatmatures April 4, 2012 and grants us the option to request annualextensions of maturity and a one-year term out period upon maturity; (v) modifiesour leverage ratio to include in the calculations of EBITDA (as defined in theSecond Amended and Restated Credit Agreement) pro forma adjustments formaterial projects and to exclude from the calculation of Consolidated FundedDebt (as defined in the Second Amended and Restated Credit Agreement) certain 

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amountsof preferred securities and subordinated debt that we or our designatedsubsidiaries may issue in the future; and (vi) eliminates our coverageratio financial covenant. Our Credit Facility continues to support ourcommercial paper program.

*Commercial Paper*

Under the terms of ourcommercial paper program, we may issue up to $600 million of commercial paper. AtJune 30, 2007, we had outstanding $393.3 million of commercial paper, netof unamortized discount of $1.7 million, bearing interest at a weighted averagerate of 5.48%. At December 31, 2006, we had $443.7 million ofcommercial paper outstanding, net of $1.3 million of unamortized discount,at a weighted average interest rate of 5.45%. At June 30, 2007, we couldissue an additional $205 million in principal amount under our commercial paperprogram.

***Cash Requirements for Future Growth***

**Capital Spending**

We expect to makesignificant expenditures during the next three years for the construction ofadditional natural gas and crude oil transportation infrastructure. In 2007, weexpect to spend approximately $2.1 billion on these and other projects with theexpectation of realizing additional cash flows as projects are completed andplaced in service. As of June 30, 2007, we have approximately $620 millionin outstanding purchase commitments for materials and services associated withour capital projects for the construction of assets that we expect to settleduring the remainder of 2007. However, we will incur additional commitments asour capital projects continue to progress.

*ForecastedExpenditures*

We categorize our capital expenditures as either coremaintenance or enhancement expenditures. Core maintenance expenditures arethose expenditures that are necessary to maintain the service capability of ourexisting assets and include the replacement of system components and equipmentwhich is worn, obsolete or completing its useful life. Enhancement expendituresimprove the service capability of our existing assets, extend asset usefullives, increase capacities from existing levels, reduce costs or enhancerevenues, and enable us to respond to governmental regulations and developingindustry standards.

We estimate our capital expenditures based upon ourstrategic operating and growth plans, which are also dependent upon our abilityto produce or otherwise obtain the capital necessary to accomplish our growthobjectives. The following table sets forth our estimates of capital requiredfor system enhancement and core maintenance expenditures through December 31,2007. Although we anticipate making the indicated expenditures, these estimatesmay change due to factors beyond our control, including weather-related issues,construction timing, changes in supplier prices or poor economic conditions.Additionally, estimates may change as a result of decisions made at a laterdate to revise the scope of a project. We made capital expenditures of$891.5 million, including $26.4 million on core maintenance activities,during the six months ended June 30, 2007.

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Forthe full year of 2007, we anticipate our capital expenditures to approximatethe following in millions:

| System  enhancements         |   | $     | 570    |   |
|------------------------------|--------|-------|--------|--------|
| Core maintenance  activities |   | 60    |   |
| Southern Access  expansion   |   | 1,050 |   |
| Alberta Clipper              |   | 120   |   |
| East Texas  expansion        |   | 300   |   |
|                         |   | $     | 2,100  |   |

 

*Major ConstructionProjects*

Thefollowing table includes our active major construction projects and additionalinformation regarding our estimated construction cost, actual expendituresthrough June 30, 2007, the incremental capacity that will become availableupon completion of the project and the periods during which we expect tocomplete the construction. From project inception, through the first six monthsof 2007, we have incurred approximately $1.5 billion of capital expendituresassociated with the projects listed below. The estimated amounts included inthis table may change due to modifications of the scope of the project,increases in materials and construction costs and other factors that areoutside of our direct control.

|                                            | ** ** | **Capital Expenditures**  | ** ** | **Estimated Incremental Capacity** | ** ** | ** **  | ** ** |
|--------------------------------------------|------------|--------------------------------|------------|----------------------------------------------|------------|-------------|------------|
| ** **                                 | ** ** | ** **                     | ** ** | **Actual  Expenditures  Inception**          | ** ** | ** **  | ** ** | ** ** | ** ** |
| ** **                                 | ** ** | **Estimated  Total Cost** | ** ** | **through  June 30, 2007**         | ** ** | **Storage** | ** ** | **Oil** | ** ** | **Natural  Gas** | ** ** | **Expected Completion** | ** ** |
| ** **                                 | ** ** | **(in billions)**         | ** ** | **(KBbl)**                                   | ** ** | **(Kbpd)**  | ** ** | **(MMcf/d)** | ** ** | ** ** | ** ** |
| Southern Access  expansion (Lakehead) |       |                           | $          | 1.8                                          |       |        |       | $ | 0.53 |   |   |   | — |   |   |   | 400 |   |   |   | — |   |   | 2009 |   |
| Clarity (East  Texas)                      |       |                           | 0.6        |                                         |       |        | 0.51       |   |   |   | — |   |   |   | — |   |   |   | 700 |   |   | In  phases to early 2008 |   |
| Alberta Clipper                            |       |                           | 1.0        |                                         |       |        | —     |   |   |   | — |   |   |   | 450 |   |   |   | — |   |   | Mid-2010 |   |
| North Dakota  system expansion             |       |                           | 0.1        |                                         |       |        | 0.03       |   |   |   | — |   |   |   | 30 |   |   |   | — |   |   | Late  2007 |   |
| Cushing terminal  storage tanks            |       |                           | 0.1        |                                         |       |        | 0.06       |   |   |   | 4,970 |   |   |   | — |   |   |   | — |   |   | Throughout  2007 |   |
| Griffith and  Superior storage tanks       |       |                           | 0.1        |                                         |       |        | 0.02       |   |   |   | 1,220 |   |   |   | — |   |   |   | — |   |   | Mid-2007  and Mid-2008 |   |
| Natural gas  connects and compression      |       |                           | 0.1        |                                         |       |        | 0.11       |   |   |   | — |   |   |   | — |   |   |   | — |   |   | Various |   |
| Processing and  treating plant expansions  |       |                           | 0.3        |                                         |       |        | 0.23       |   |   |   | — |   |   |   | — |   |   |   | 1,130 |   |   | Various |   |
| Total                                      |       |                           | $          | 4.1                                          |       |        |       | $ | 1.49 |   |   |   | 6,190 |   |   |   | 880 |   |   |   | 1,830 |   |   |   |   |

 

Including major expansion projects and excludingacquisitions, ongoing capital expenditures are expected to be significant overthe next three years due to our East Texas expansion and extension, SouthernAccess expansion and Alberta Clipper projects. Core maintenance capital is alsoanticipated to increase over that period of time due to growth in our pipelinesystems and aging of infrastructure.

We anticipate funding the system enhancement capitalexpenditures temporarily through the issuance of commercial paper and borrowingunder the terms of our Credit Facility, with permanent debt and equity fundingbeing obtained when appropriate. Core maintenance expenditures are expected tobe funded by operating cash flows.

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We expect to incurcontinuing annual capital and operating expenditures for pipeline integritymeasures to ensure both regulatory compliance and to maintain the overallintegrity of our pipeline systems. Expenditure levels have continued toincrease as pipelines age and require higher levels of inspection ormaintenance; however, these are viewed to be consistent with industry trends.

***Derivative Activities***

We use derivative financial instruments (i.e.,futures, forwards, swaps, options and other financial instruments with similarcharacteristics) to mitigate the volatility of our cash flows and manage therisks associated with market fluctuations in commodity prices. Based on ourrisk management policies, all of our derivative financial instruments are employedin connection with an underlying asset, liability or anticipated transactionand are not entered into with the objective of speculating on commodity prices.

Thefollowing table provides summarized information about the timing and expectedsettlement amounts of our outstanding commodity derivative financialinstruments at June 30, 2007 for each of the indicated calendar years:

| ** **             | ** ** | **Notional**                  | ** ** | **2007** | ** ** | **2008** | ** ** | **2009** | ** ** | **2010** | ** ** | **2011** | ** ** | **2012** | ** ** |
|------------------------|------------|-------------------------------|------------|----------|------------|----------|------------|----------|------------|----------|------------|----------|------------|----------|------------|
| ** **             | ** ** | **($ in millions)** | ** ** |
| **Swaps**              |       |                          |       |     |       |     |       |     |       |     |       |     |       |     |       |
| Natural gas(1)         |       | 257,949,129                   |       | $        | (17.3      | )        | $          | (37.7    | )          | $        | (34.6      | )        | $          | (29.5    | )          | $ | (26.0 | ) | $ | (5.1 | ) |
| NGL(2)                 |       | 7,808,300                     |       | (25.1    | )          | (20.8    | )          | (10.8    | )          | (5.2     | )          | (1.6     | )          | —   |       |
| Crude(2)               |       | 1,187,779                     |       | (5.5     | )          | (8.7     | )          | (3.1     | )          | (1.6     | )          | (1.0     | )          | —   |       |
| **Options—calls** |       |                          |       |     |       |     |       |     |       |     |       |     |       |     |       |
| Natural gas(1)         |       | 1,645,000                     |       | (0.6     | )          | (1.4     | )          | (1.4     | )          | (1.3     | )          | (1.1     | )          | —   |       |
| **Options—puts**  |       |                          |       |     |       |     |       |     |       |     |       |     |       |     |       |
| Natural gas(1)         |       | 2,135,000                     |       | 0.3      |       | —   |       | —   |       | —   |       | —   |       | —   |       |
| Totals                 |       |                          |       | $        | (48.2      | )        | $          | (68.6    | )          | $        | (49.9      | )        | $          | (37.6    | )          | $ | (29.7 | ) | $ | (5.1 | ) |

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(1)                Notionalamounts for natural gas are recorded in MMBtu.

(2)                Notionalamounts for NGL and Crude are recorded in Bbl.

***Operating Activities***

Net cash provided byoperating activities for the six months ended June 30, 2007 was $258.7million, an increase of $91.7 million from the $167.0 million generatedduring the same period in 2006. The improved operating cash flow is primarilyattributable to sales of inventory in the first half of 2007 that we did notmake in the first half of 2006, and other changes in working capital accounts.Additional, net cash provided by operating activities increased due to thegeneral timing differences in the collection on and payment of our current andrelated party accounts.

***Investing Activities***

Net cash used in ourinvesting activities during the six months ended June 30, 2007 was $805.4million, an increase of $491.9 million from the $313.5 million used during thesame period of 2006. The increase is primarily attributable to the $606.3million increase in our investments in property, plant and equipment during thefirst six months of 2007, over the amount spent during the same period of 2006,partially offset by an $82.4 million increase in our construction payables andno acquisitions in 2007. The increase in our capital expenditures during thefirst six months of 2007 is directly attributable to our previously announcedexpansion projects.

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***Financing Activities***

Net cash provided byfinancing activities during the six months ended June 30, 2007 was$466.5 million, an increase of $320.6 million from the $145.9 milliongenerated during the same period in 2006. The increase in cash flow fromfinancing activities is primarily attributable to our unit issuances, which arepartially offset by net repayments of commercial paper. During the first sixmonths of 2007 we issued a total of 11.2 million Class A and C units fornet proceeds of approximately $628.8 million and made $46.5 million in netrepayments of commercial paper, which include gross issuances of $2,495.7million and gross repayments of $2,542.2 million.

**OFF-BALANCESHEET ARRANGEMENTS**

We have no significant off-balancesheet arrangements.

**SUBSEQUENT EVENTS**

*Distribution toPartners*

On July 27, 2007, theBoard of Directors of Enbridge Management declared a distribution payable toour partners on August 14, 2007. The distribution will be paid tounitholders of record as of August 6, 2007, of our available cash of $92.6million at June 30, 2007, or $0.925 per common unit. Of this distribution,$63.7 million will be paid in cash, $12.1 million will be distributed in i-unitsto our i-unitholder, $16.2 million will be distributed in Class Cunits to the holders of our Class C units and $0.6 million will beretained from the General Partner in respect of the i-unit andClass C unit distributions.

**REGULATORY MATTERS**

***FERC Transportation Tariffs-***Liquids

Effective July 1, 2007, we increased our ratesfor transportation on our Lakehead, North Dakota and Ozark systems incompliance with the indexed rate ceilings allowed by the FERC. InMarch 2006, The FERC determined that the Producer Price Index For FinishedGoods plus 1.3 percent (PPI + 1.3 percent) should be the oil pricing index fora five year period ending July 2011. The index is used to establish rateceiling levels for oil pipeline rate changes. For our Lakehead system, indexingonly applies to the base rates, not the SEP II, Terrace and Facilitiessurcharges.  Effective July 2007, weincreased the transportation rates on our Lakehead system by an average of 4.5percent. Our Lakehead system base tariff rates are slightly below the indexedceiling level allowed under the FERC’s indexing methodology. On our Lakeheadsystem, the new rate for heavy crude movements from the International Bordernear Neche, North Dakota to Chicago, Illinois is $0.958 per barrel, whichreflects a $0.032 per barrel increase over the rates filed effectiveApril 1, 2007. In addition to the rates on our Lakehead system, weincreased the transportation rates on our North Dakota and Ozark systems by anaverage of 4.3 percent. The tariff rates for our North Dakota and Ozark systemsare at the ceiling levels allowed under the FERC methodology.

Effective April 1,2007, we filed our annual tariff with the FERC for our Lakehead system toreflect the annual calculation of the SEP II and other surcharges based ontrue-ups of prior year amounts and estimates for 2007, as well as an adjustmentfor the Terrace surcharge due to lower than expected volumes moving on theLakehead system in 2006. These surcharges compensate Lakehead for expansions ofthe system completed in prior years. This filing increased the tariff for heavycrude oil movements from the Canadian border to Chicago by approximately $0.007per barrel, to approximately $0.926 per barrel.

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**RECENT ACCOUNTINGPRONOUNCEMENTS NOT YET ADOPTED**

In February 2007, theFASB issued SFAS No. 159, *The Fair Value Option forFinancial Assets and Liabilities.*This statement provides companieswith an option to report certain financial assets and financial liabilities atfair value. The objective of SFAS No. 159 is to reduce the volatility inearnings caused by measuring related assets and liabilities differently withouthaving to apply complex hedge accounting provisions. SFAS No. 159 alsoestablishes presentation and disclosure requirements designed to facilitatecomparisons between companies that choose different measurement attributes forsimilar types of assets and liabilities. The provisions of SFAS No. 159are effective at the beginning of our first fiscal year that begins afterNovember 15, 2007, as we have elected not to early adopt the provisions ofSFAS No. 159. We do not expect our adoption of SFAS No. 159 tohave a material effect on our Consolidated Financial Statements.

**Item3.**                        Quantitativeand Qualitative Disclosures About Market Risk

The following should be read in conjunction with theinformation presented in our Annual Report on Form 10-K for the yearended December 31, 2006, in addition to information presented in Items 1and 2 of this Quarterly Report on Form 10-Q. There have been nomaterial changes to that information other than as presented below.

Our net income and cash flows are subject tovolatility stemming from changes in commodity prices of natural gas, NGLs,condensate and fractionation margins (the relative price differential betweenNGL sales and the offsetting natural gas purchases). Our exposure to commodityprice risk exists within our Natural Gas and Marketing segments. To mitigatethe volatility of our cash flows, we use derivative financial instruments(i.e., futures, forwards, swaps, options and other financial instruments withsimilar characteristics) to manage the risks associated with marketfluctuations in commodity prices. Based on our risk management policies, all ofour derivative financial instruments are employed in connection with anunderlying asset, liability or forecasted transaction and are not entered intowith the objective of speculating on commodity prices.

The following tablesprovide information about our derivative financial instruments at June 30,2007 and December 31, 2006, with respect to our commodity price riskmanagement activities for natural gas and NGLs, including condensate:

|                                  | ** **   | **At June 30, 2007** | ** **   | **At December 31, 2006** | ** **   |
|----------------------------------|--------------|-------------------------------------|--------------|-----------------------------------------|--------------|
| ** **                       | ** **   | ** **                          | ** **   | ** **                              | ** **   | **Wtd Avg Price**(2) | ** ** | **Fair Value**(3) | ** ** | **Fair Value**(3) | ** ** |
| ** **                       | ** **   | **Commodity**                       | ** **   | **Notional**(1)                         | ** **   | **Receive** | ** ** | **Pay** | ** ** | **Asset** | ** ** | **Liability** | ** ** | **   Asset   ** | ** ** | **   Liability   ** | ** ** |
| ***Contracts maturing in 2007*** | *** *** | *** ***                        | *** *** | *** ***                            | *** *** |   | *** *** | *** *** |   | *** *** | *** *** | *** *** | *** *** |   | *** *** | *** *** |   |   | *** *** | *** *** |   |   | *** *** | *** *** |   |
| *Swaps*                          | * *     | * *                            | * *     | * *                                | * *     |   | * * | * * |   | * * | * * | * * | * * |   | * * | * * |   |   | * * | * * |   |   | * * | * * |   |
| Receive variable/pay fixed       |         | Natural gas                         |         | 25,880,780                              |         |   | $ | 6.77 |   |   | $ | 7.45 |   | $ | 5.1 |   |   | $ | (22.3 | ) |   |   | $ | 8.1 |   |   |   | $ | (86.7 | ) |   |
|                                  |         | NGL                                 |         | 50,232                                  |         |   | 47.51 |   |   | 43.65 |   | 0.2 |   |   | — |   |   |   | — |   |   |   | (0.5 | ) |   |
| Receive fixed/pay variable       |         | Natural gas                         |         | 27,874,594                              |         |   | 7.03 |   |   | 7.05 |   | 18.4 |   |   | (18.8 | ) |   |   | 79.8 |   |   |   | (33.0 | ) |   |
|                             |         | NGL                                 |         | 2,193,464                               |         |   | 38.16 |   |   | 49.89 |   | — |   |   | (25.3 | ) |   |   | 14.4 |   |   |   | (23.2 | ) |   |
|                             |         | Crude oil                           |         | 189,888                                 |         |   | 41.71 |   |   | 71.23 |   | — |   |   | (5.5 | ) |   |   | — |   |   |   | (8.6 | ) |   |
| Receive variable/pay variable    |         | Natural gas                         |         | 53,443,656                              |         |   | 6.84 |   |   | 6.84 |   | 2.7 |   |   | (2.4 | ) |   |   | 3.1 |   |   |   | (3.7 | ) |   |
| *Options*                        | * *     | * *                            | * *     | * *                                | * *     |   | * * | * * |   | * * | * * | * * | * * |   | * * | * * |   |   | * * | * * |   |   | * * | * * |   |
| Calls (written)                  |         | Natural gas                         |         | 184,000                                 |         |   | 7.33 |   |   | 4.31 |   | — |   |   | (0.6 | ) |   |   | — |   |   |   | (1.0 | ) |   |
| Puts                             |         | Natural gas                         |         | 674,000                                 |         |   | 7.14 |   |   | 6.15 |   | 0.3 |   |   | — |   |   |   | 1.0 |   |   |   | — |   |   |
|                                  |              |                                     |              |                                         |              |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |

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| ***Contracts maturing in 2008***    |         |         |         |         |         |   |         |         |   |         |         |         |         |   |         |         |   |   |         |         |   |   |         |         |   |
|-------------------------------------|--------------|--------------|--------------|--------------|--------------|--------|--------------|--------------|--------|--------------|--------------|--------------|--------------|--------|--------------|--------------|--------|--------|--------------|--------------|--------|--------|--------------|--------------|--------|
| *Swaps*                             | * *     | * *     | * *     | * *     | * *     |   | * *     | * *     |   | * *     | * *     | * *     | * *     |   | * *     | * *     |   |   | * *     | * *     |   |   | * *     | * *     |   |
| Receive variable/pay fixed          |         | Natural gas  |         | 20,975,750   |         |   | 7.88         |         |   | 7.48         |         | 12.3         |         |   | (4.1         | )            |   |   | 9.5          |         |   |   | (5.1         | )            |   |
| Receive fixed/pay  variable         |         | Natural gas  |         | 25,386,896   |         |   | 6.37         |         |   | 8.36         |         | 2.0          |         |   | (50.1        | )            |   |   | 3.6          |         |   |   | (44.1        | )            |   |
|                                |         | NGL          |         | 2,603,724    |         |   | 39.78        |         |   | 48.21        |         | —       |         |   | (20.8        | )            |   |   | 2.5          |         |   |   | (7.7         | )            |   |
|                                |         | Crude oil    |         | 337,241      |         |   | 45.16        |         |   | 72.35        |         | —       |         |   | (8.7         | )            |   |   | —       |         |   |   | (7.0         | )            |   |
| Receive variable/pay variable       |         | Natural gas  |         | 32,714,803   |         |   | 8.35         |         |   | 8.28         |         | 3.2          |         |   | (1.0         | )            |   |   | 2.5          |         |   |   | (0.4         | )            |   |
| *Options*                           | * *     | * *     | * *     | * *     | * *     |   | * *     | * *     |   | * *     | * *     | * *     | * *     |   | * *     | * *     |   |   | * *     | * *     |   |   | * *     | * *     |   |
| Calls (written)                     |         | Natural gas  |         | 366,000      |         |   | 8.40         |         |   | 4.31         |         | —       |         |   | (1.4         | )            |   |   | —       |         |   |   | (1.3         | )            |   |
| Puts                                |         | Natural gas  |         | 366,000      |         |   | 8.40         |         |   | 3.40         |         | —       |         |   | —       |         |   |   | —       |         |   |   | —       |         |   |
| ***Contracts maturing in 2009***    | *** *** | *** *** | *** *** | *** *** | *** *** |   | *** *** | *** *** |   | *** *** | *** *** | *** *** | *** *** |   | *** *** | *** *** |   |   | *** *** | *** *** |   |   | *** *** | *** *** |   |
| *Swaps*                             | * *     | * *     | * *     | * *     | * *     |   | * *     | * *     |   | * *     | * *     | * *     | * *     |   | * *     | * *     |   |   | * *     | * *     |   |   | * *     | * *     |   |
| Receive variable/pay fixed          |         | Natural gas  |         | 6,846,254    |         |   | 8.13         |         |   | 7.40         |         | 5.2          |         |   | (0.6         | )            |   |   | 2.9          |         |   |   | (2.1         | )            |   |
| Receive fixed/pay  variable         |         | Natural gas  |         | 12,985,240   |         |   | 5.18         |         |   | 8.57         |         | 0.2          |         |   | (39.9        | )            |   |   | 0.7          |         |   |   | (31.5        | )            |   |
|                                |         | NGL          |         | 1,927,565    |         |   | 42.43        |         |   | 48.67        |         | —       |         |   | (10.8        | )            |   |   | 1.4          |         |   |   | (1.4         | )            |   |
|                                |         | Crude oil    |         | 264,625      |         |   | 59.09        |         |   | 72.38        |         | —       |         |   | (3.1         | )            |   |   | —       |         |   |   | (1.9         | )            |   |
| Receive variable/pay variable       |         | Natural gas  |         | 20,622,611   |         |   | 8.78         |         |   | 8.75         |         | 1.4          |         |   | (0.9         | )            |   |   | 1.4          |         |   |   | (0.6         | )            |   |
| *Options*                           | * *     | * *     | * *     | * *     | * *     |   | * *     | * *     |   | * *     | * *     | * *     | * *     |   | * *     | * *     |   |   | * *     | * *     |   |   | * *     | * *     |   |
| Calls (written)                     |         | Natural gas  |         | 365,000      |         |   | 8.55         |         |   | 4.31         |         | —       |         |   | (1.4         | )            |   |   | —       |         |   |   | (1.2         | )            |   |
| Puts                                |         | Natural gas  |         | 365,000      |         |   | 8.55         |         |   | 3.40         |         | —       |         |   | —       |         |   |   | —       |         |   |   | —       |         |   |
| ***Contracts maturing in 2010***    | *** *** | *** *** | *** *** | *** *** | *** *** |   | *** *** | *** *** |   | *** *** | *** *** | *** *** | *** *** |   | *** *** | *** *** |   |   | *** *** | *** *** |   |   | *** *** | *** *** |   |
| *Swaps*                             | * *     | * *     | * *     | * *     | * *     |   | * *     | * *     |   | * *     | * *     | * *     | * *     |   | * *     | * *     |   |   | * *     | * *     |   |   | * *     | * *     |   |
| Receive variable/pay fixed          |         | Natural gas  |         | 2,228,045    |         |   | 8.11         |         |   | 6.10         |         | 3.8          |         |   | —       |         |   |   | 2.5          |         |   |   | (0.3         | )            |   |
| Receive fixed/pay  variable         |         | Natural gas  |         | 9,670,000    |         |   | 4.19         |         |   | 8.31         |         | —       |         |   | (34.0        | )            |   |   | 0.2          |         |   |   | (26.1        | )            |   |
|                                |         | NGL          |         | 784,750      |         |   | 33.94        |         |   | 41.69        |         | —       |         |   | (5.2         | )            |   |   | —       |         |   |   | (1.5         | )            |   |
|                                |         | Crude oil    |         | 213,525      |         |   | 63.00        |         |   | 71.79        |         | —       |         |   | (1.6         | )            |   |   | —       |         |   |   | (0.6         | )            |   |
| Receive variable/pay variable       |         | Natural gas  |         | 9,000,000    |         |   | 9.09         |         |   | 9.00         |         | 1.0          |         |   | (0.3         | )            |   |   | 0.8          |         |   |   | (0.1         | )            |   |
| *Options*                           | * *     | * *     | * *     | * *     | * *     |   | * *     | * *     |   | * *     | * *     | * *     | * *     |   | * *     | * *     |   |   | * *     | * *     |   |   | * *     | * *     |   |
| Calls (written)                     |         | Natural gas  |         | 365,000      |         |   | 8.36         |         |   | 4.31         |         | —       |         |   | (1.3         | )            |   |   | —       |         |   |   | (1.0         | )            |   |
| Puts                                |         | Natural gas  |         | 365,000      |         |   | 8.36         |         |   | 3.40         |         | —       |         |   | —       |         |   |   | —       |         |   |   | —       |         |   |
| ***Contracts maturing in 2011***    | *** *** | *** *** | *** *** | *** *** | *** *** |   | *** *** | *** *** |   | *** *** | *** *** | *** *** | *** *** |   | *** *** | *** *** |   |   | *** *** | *** *** |   |   | *** *** | *** *** |   |
| *Swaps*                             | * *     | * *     | * *     | * *     | * *     |   | * *     | * *     |   | * *     | * *     | * *     | * *     |   | * *     | * *     |   |   | * *     | * *     |   |   | * *     | * *     |   |
| Receive variable/pay fixed          |         | Natural gas  |         | 730,000      |         |   | 8.08         |         |   | 3.57         |         | 2.6          |         |   | —       |         |   |   | 2.0          |         |   |   | —       |         |   |
| Receive fixed/pay  variable         |         | Natural gas  |         | 7,952,500    |         |   | 3.63         |         |   | 8.07         |         | —       |         |   | (28.6        | )            |   |   | —       |         |   |   | (21.5        | )            |   |
|                                |         | NGL          |         | 248,565      |         |   | 32.12        |         |   | 40.31        |         | —       |         |   | (1.6         | )            |   |   | —       |         |   |   | (0.6         | )            |   |
|                                     |         | Crude oil    |         | 182,500      |         |   | 64.30        |         |   | 71.28        |         | —       |         |   | (1.0         | )            |   |   | —       |         |   |   | (0.2         | )            |   |
| *Options*                           | * *     | * *     | * *     | * *     | * *     |   | * *     | * *     |   | * *     | * *     | * *     | * *     |   | * *     | * *     |   |   | * *     | * *     |   |   | * *     | * *     |   |
| Calls (written)                     |         | Natural gas  |         | 365,000      |         |   | 8.08         |         |   | 4.31         |         | —       |         |   | (1.1         | )            |   |   | —       |         |   |   | (0.9         | )            |   |
| Puts                                |         | Natural gas  |         | 365,000      |         |   | 8.08         |         |   | 3.40         |         | —       |         |   | —       |         |   |   | —       |         |   |   | —       |         |   |
| ***Contracts maturing after 2011*** | *** *** | *** *** | *** *** | *** *** | *** *** |   | *** *** | *** *** |   | *** *** | *** *** | *** *** | *** *** |   | *** *** | *** *** |   |   | *** *** | *** *** |   |   | *** *** | *** *** |   |
| *Swaps*                             | * *     | * *     | * *     | * *     | * *     |   | * *     | * *     |   | * *     | * *     | * *     | * *     |   | * *     | * *     |   |   | * *     | * *     |   |   | * *     | * *     |   |
| Receive variable/pay fixed          |         | Natural gas  |         | 182,000      |         |   | 8.73         |         |   | 3.57         |         | 0.7          |         |   | —       |         |   |   | 0.6          |         |   |   | —       |         |   |
| Receive fixed/pay variable          |         | Natural gas  |         | 1,456,000    |         |   | 3.57         |         |   | 8.73         |         | —       |         |   | (5.8         | )            |   |   | —       |         |   |   | (4.5         | )            |   |

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(1)                Volumes of Natural gas are measured inMMBtu, whereas volumes of NGL and Crude are measured in Bbl.

(2)                Weighted average prices received and paidare in $/MMBtu for Natural gas and in $/Bbl for NGL and Crude.

(3)                The fair value is determined based onquoted market prices at June 30, 2007 and December 31, 2006,respectively, discounted using the swap rate for the respective periods toconsider the time value of money. Fair values are presented in millions ofdollars.

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**Item 4.**                        Controlsand Procedures

The Partnership and Enbridge maintain systems ofdisclosure controls and procedures designed to provide reasonable assurancethat we are able to record, process, summarize and report the informationrequired in our annual and quarterly reports under the Securities Exchange Actof 1934. Our management has evaluated the effectiveness of our disclosurecontrols and procedures as of June 30, 2007. Based upon that evaluation,our principal executive officer and principal financial officer concluded thatour disclosure controls and procedures are effective to accomplish theirpurpose. In conducting this assessment, our management relied on similarevaluations conducted by employees of Enbridge affiliates who provide certaintreasury, accounting and other services on our behalf. No changes in ourinternal control over financial reporting were made during the three monthsended June 30, 2007 that would materially affect our internal control overfinancial reporting, nor were any corrective actions with respect tosignificant deficiencies or material weaknesses necessary subsequent to thatdate.

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**PART II—OTHERINFORMATION**

**Item1.**                        LegalProceedings

Refer to Part I,Item 1. Financial statements, Note 9, which is incorporated herein byreference.

**Item1A.**                Risk Factors

The risk factors presentedbelow update and should be considered in addition to the risk factorspreviously disclosed in our Annual Report on Form 10-K for thefiscal year ended December 31, 2006.

**RISKS RELATED TOOUR BUSINESS**

***Changes in ourtariff rates or challenges to our tariff rates could have a material adverseeffect on our financial condition and results of operations.***

The tariff rates charged by several of our existingpipeline systems are regulated by the FERC, or various state regulatoryagencies. If one of these regulatory agencies, on its own initiative or due tochallenges by third parties, were to lower our tariff rates, the profitabilityof our pipeline businesses might suffer. If we were permitted to raise ourtariff rates for a particular pipeline, there might be significant delaybetween the time the tariff rate increase is approved and the time that therate increase actually goes into effect, which delay could further reduce ourcash flow. Furthermore, competition from other pipeline systems may prevent usfrom raising our tariff rates even if regulatory agencies permit us to do so.The regulatory agencies that regulate our systems periodically propose andimplement new rules and regulations, terms and conditions of servicessubject to their jurisdiction. New initiatives or orders may adversely affectthe tariff rates charged for our services. Some producing states, includingOklahoma and Texas, are considering legislation that would require rate and/orservice regulation of gathering and intrastate transmission natural gassystems. Increased state regulation could adversely impact our natural gassystems.

The question of whether and to what extent an incometax allowance should be included in a regulated utility’s cost of service forrate-making purposes has been a matter of uncertainty for a number of years andhas been pending judicial review. On May 29, 2007 the United States Courtof Appeals for the District of Columbia Circuit (the “DC Circuit”) deniedpetitions for review of the FERC’s income tax allowance (“ITA”) policy. The DCCircuit, which previously vacated and remanded prior FERC orders on thesubject, affirmed the ITA policy that the FERC adopted in its May 4, 2005,Policy Statement on Income Tax Allowances, 111 FERC ¶ 61,139 (“Policy Statement”)which concluded that “such an allowance should be permitted on all partnershipinterests, or similar legal interests, if the owner of that interest has anactual or potential income tax liability on the public utility income earnedthrough the interest,” thereby extending the ITA to both corporations andpartnerships (or other pass-through entities). The DC Circuit’s opinion is notyet final, and is subject to potential requests for rehearing and/or review bythe United States Supreme Court. In addition, the FERC’s Policy Statementcontemplates that individual rate proceedings will determine “whether aparticular partner ... has an actual or potential income tax liability, and whatassumptions, if any, should determine the amount of the related tax rate ...”

A related issue is whether the FERC’s Policy Statementcan be relied upon by shippers as a substantial change in circumstancessufficient to remove the grandfathering protection under the Energy Policy Actof 1992 (“EP Act”) from an oil pipeline’s rates. As part of its May 29,2007 opinion, the DC Circuit denied the petitions for review with respect tothe EP Act issues and upheld the FERC’s interpretation of the EP Act asreasonable. As noted above, the DC Circuit’s opinion is not yet final.

We believe that the rateswe charge for transportation services on our interstate common carrier liquidspipelines are just and reasonable under the Interstate Commerce Act. However,because the rates that we charge are subject to review upon an appropriatelysupported protest or complaint, we cannot 

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predictwhat rates we will be allowed to charge in the future for service on ourinterstate common carrier liquids pipelines. Furthermore, because rates chargedfor transportation services must be competitive with those charged by othertransporters, the rates set forth in our tariffs will be determined based oncompetitive factors in addition to regulatory considerations.

**TAX RISKS TO COMMONUNITHOLDERS**

***We may beclassified as an association taxable as a corporation rather than as apartnership, which would substantially reduce the value of our Class ACommon Units.***

We could be treated as a corporation for federalincome tax purposes. Our treatment as a corporation would substantially reducethe cash distributions on the Class A Common Units that we distributequarterly. Moreover, treatment of us as a corporation could materially andadversely affect our ability to make payments on our debt securities. Theanticipated benefit of an investment in our Class A Common Units dependslargely on the treatment of us as a partnership for federal income taxpurposes. Under current law, we are treated as a partnership for federal incometax purposes and do not pay any federal income tax at the entity level. Inorder to qualify for this treatment, we must derive more than 90% of our annualgross income from specified investments and activities. While we believe thatwe currently do qualify and intend to meet this income requirement, we may notfind it possible, regardless of our efforts, to meet this income requirement ormay inadvertently fail to meet this income requirement. Current law may changeso as to cause us to be treated as a corporation for federal income taxpurposes without regard to our sources of income or otherwise subject us toentity-level taxation. If we were to be treated as a corporation for federalincome tax purposes, we would pay federal income tax on our income at thecorporate tax rate, which is currently a maximum of 35% and would pay stateincome taxes at varying rates. Under current law, distributions to unitholderswould generally be taxed as a corporate distribution. Because a tax would beimposed upon us as a corporation, the cash available for distribution to aunitholder would be substantially reduced. Treatment of us as a corporationwould cause a substantial reduction in the value of our Class A CommonUnits.

In addition, severalstates are evaluating ways to subject partnerships to entity-level taxationthrough the imposition of state income, franchise, or other forms of taxation.State tax legislation resulting in the imposition of a partnership-level incometax on us would reduce the cash distributions on the Class A Common Unitsand the value of the i-units that we will distribute quarterly to EnbridgeManagement. The enactment of significant legislation imposing partnership-levelincome taxes could cause a reduction in the value of our Class A CommonUnits.

***If the InternalRevenue Service does not respect our curative tax allocations, the after-taxreturn to our unitholders on their investment in our Class A Common Unitswould be adversely affected.***

Our partnership agreementallows curative allocations of income, deduction, gain and loss by us toaccount for differences between the tax basis and fair market value of propertyat the time the property is contributed or deemed contributed to us and toaccount for differences between the fair market value and S-8 book basisof our assets existing at the time of issuance of any Class A CommonUnits. If the Internal Revenue Service, which we refer to as the IRS, does notrespect our curative allocations, ratios of taxable income to cashdistributions received by the holders of Class A Common Units will bematerially higher than previously estimated.

***The tax liabilityof our unitholders could exceed their distributions or proceeds from sales of Class ACommon Units.***

The holders of our Class ACommon Units will be required to pay federal income tax and, in some cases,state and local income taxes on their allocable share of our income, even ifthey do not receive cash 

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distributionsfrom us. They will not necessarily receive cash distributions equal to the taxon their allocable share of our taxable income. Further, if we have a largeamount of nonrecourse liabilities, they may incur a tax liability that isgreater than the money they receive when they sell their Class A CommonUnits.

***A unitholder may berequired to file tax returns with and pay income taxes to the states where weor our***subsidiaries own property and conduct business.

In some cases, aunitholder may be required to file income tax returns with and pay income taxesto the states in which we or our subsidiaries own property and conductbusiness, which are currently Alabama, Arkansas, Florida, Georgia, Illinois,Indiana, Kansas, Kentucky, Louisiana, Michigan, Minnesota, Mississippi,Missouri, Montana, New York, North Carolina, North Dakota, Oklahoma, SouthCarolina, Tennessee, Texas and Wisconsin. In the future, we may acquireproperty or do business in other states or in foreign jurisdictions. Inaddition to tax liabilities to such state and foreign jurisdictions, the ownerof a Class A Common Unit may also incur tax and filing responsibilities tolocalities within such jurisdictions.

***Ownership of Class ACommon Units raises issues for tax-exempt entities and other investors.***

An investment in our Class ACommon Units by tax-exempt entities, including employee benefit plans,individual retirement accounts, Keogh plans and other retirement plans,regulated investment companies and foreign persons raises issues unique tothem. Virtually all of the income derived from our Class A Common Units bya tax-exempt entity will be “unrelated business taxable income” and will betaxable to the tax-exempt entity. Further, a unitholder who is a nonresidentalien, a foreign corporation or other foreign person will be required to file afederal income tax return and pay tax on his share of our taxable incomebecause he will be regarded as being engaged in a trade or business in theUnited States as a result of his ownership of a Class A Common Unit.

***We have adoptedcertain valuation methodologies that may result in a shift of income, gain,loss and deduction between the general partner and the unitholders. The IRS maychallenge this treatment, which could adversely affect the value of the Class ACommon Units.***

When we issue additional Class A Common Units orengage in certain other transactions, we determine the fair market value of ourassets and allocate any unrealized gain or loss attributable to our assets tothe capital accounts of our unitholders and our general partner. Ourmethodology may be viewed as understating the value of our assets. In thatcase, there may be a shift of income, gain, loss and deduction between certainunitholders and the general partner, which may be unfavorable to suchunitholders. Moreover, subsequent purchasers of Class A Common Units mayhave a greater portion of their Internal Revenue Code Section 743(b) adjustmentallocated to our tangible assets and a lesser portion allocated to ourintangible assets. The IRS may challenge our valuation methods, or ourallocation of the Section 743(b) adjustment attributable to ourtangible and intangible assets, and allocations of income, gain, loss anddeduction between the general partner and certain of our unitholders.

A successful IRS challengeto these methods or allocations could adversely affect the amount of taxableincome or loss being allocated to our unitholders. It also could affect theamount of gain from our unitholders’ sale of Class A Common Units andcould have a negative impact on the value of the Class A Common Units orresult in audit adjustments to our unitholders’ tax returns without the benefitof additional deductions.

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***We treat eachpurchaser of Class A Common Units as having the same tax benefits withoutregard to the actual Class A Common Units purchased. The IRS may challengethis treatment, which could result in a unitholder owing more tax and mayadversely affect the value of the Class A Common Units.***

To maintain the uniformity of the economic and tax characteristicsof our Class A Common Units, we have adopted certain depreciation andamortization positions that are inconsistent with existing Treasuryregulations. These positions may result in an understatement of deductions andlosses and an overstatement of income and gain to our unitholders. For example,we do not amortize certain goodwill assets, the value of which has beenattributed to certain of our outstanding Class A Common Units. Asubsequent holder of those Class A Common Units is entitled to anamortization deduction attributable to that goodwill under Internal RevenueCode Section 743(b). However, because we cannot identify these Class ACommon Units once they are traded by the initial holder, we do not give anysubsequent holder of a Class A Common Unit any such amortizationdeduction. This approach understates deductions available to those unitholderswho own those Class A Common Units and results in a reduction in the taxbasis of those Class A Common Units by the amount of the deductions thatwere allowable but were not taken.

The IRS may challenge themanner in which we calculate our unitholder’s basis adjustment under InternalRevenue Code Section 743(b). If so, because neither we nor a unitholdercan identify the Class A Common Units to which this issue relates once theinitial holder has traded them, the IRS may assert adjustments to allunitholders selling Class A Common Units within the period under audit asif all unitholders owned Class A Common Units with respect to whichallowable deductions were not taken. Any position we take that is inconsistentwith applicable Treasury regulations may have to be disclosed on our federalincome tax return. This disclosure increases the likelihood that the IRS willchallenge our positions and propose adjustments to some or all of ourunitholders. A successful IRS challenge to this position or other positions wemay take could adversely affect the amount of taxable income or loss allocatedto our unitholders. It also could affect the gain from a unitholder’s sale of Class ACommon Units and could have a negative impact on the value of the Class ACommon Units or result in audit adjustments to our unitholders’ tax returnswithout the benefit of additional deductions.

**Item6.**                        Exhibits

Reference is made to the “Index of Exhibits” followingthe signature page, which we hereby incorporate into this Item.

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**SIGNATURES**

Pursuantto the requirements of the Securities Exchange Act of 1934, the Registrant hasduly caused this report to be signed on its behalf by the undersigned thereuntoduly authorized.
|                          | ** ** | **ENBRIDGE ENERGY PARTNERS, L.P.**                                                                          |
|--------------------------|------------|-------------------------------------------------------------------------------------------------------------|
|                     |       | (Registrant)                                                                                                |
|                     | By:        | Enbridge Energy  Management, L.L.C.  as delegate of  Enbridge Energy Company, Inc.  as General Partner |
| Date: July 30, 2007 | By:        | /s/ STEPHEN J.J. LETWIN                                                                                     |
|                     |       | Stephen J. J. Letwin                                                                                        |
| * *                 | * *   | *Managing Director*                                                                                         |
| * *                 | * *   | *(Principal Executive Officer)*                                                                             |
| Date: July 30, 2007 | By:        | /s/ MARK A. MAKI                                                                                            |
|                     |       | Mark A. Maki                                                                                                |
| * *                 | * *   | *Vice President, Finance*                                                                                   |
| * *                 | * *   | *(Principal Financial Officer)*                                                                             |

 

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**Index of Exhibits**

Eachexhibit identified below is filed as part of this document. Exhibits notincorporated by reference to a prior filing are designated by an “*”; allexhibits not so designated are incorporated herein by reference to a previousfiling as indicated.

| 3.1   |   | Certificate of Limited  Partnership of the Partnership (incorporated by reference to Exhibit 3.1  to the Partnership’s Registration Statement No. 33-43425).                                                                                                                                                                                                        |
|-------|--------|------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
| 3.2   |   | Certificate of  Amendment to Certificate of Limited Partnership of the Partnership  (incorporated by reference to Exhibit 3.2 to the Partnership’s 2000  Form 10-K/A dated October 9, 2001).                                                                                                                                                                   |
| 3.3   |   | Fourth Amended  and Restated Agreement of Limited Partnership of the Partnership, dated August 15,  2006 (incorporated by reference to Exhibit 3.1 of our Current Report on  Form 8-K dated August 16, 2006).                                                                                                                                                  |
| 4.1   |   | Form of  Certificate representing Class A Common Units (incorporated by reference  to Exhibit 4.1 to the Partnership’s 2000 Form 10-K/A dated  October 9, 2001).                                                                                                                                                                                     |
| 4.2   |   | Registration  Rights Agreement, dated April 2, 2007 by and among Enbridge Energy  Partners, L.P. Tortoise Energy Infrastructure Corporation, Tortoise Energy  Capital Corporation and CDP Infrastructures Fund G.P. (incorporated by reference  to Exhibit 4.1 of the Partnership’s Current Report on Form 8-K  dated April 2, 2007).                     |
| 10.1  |   | Second Amended  and Restated Credit Agreement dated as of April 4, 2007, by and among  the Partnership, the lenders from time to time parties thereto, and Bank of  America, N.A., as administrative agent (incorporated by reference to  Exhibit 10.1of the Partnership’s Current Report on Form 8-K  dated April 10, 2007).                             |
| 10.2  |   | Common Unit  Purchase Agreement (incorporated by reference to Exhibit 1.1 of the  Partnership’s Current Report on Form 8-K filed on May 17,  2007).                                                                                                                                                                                                            |
| 10.3* |   | Offer of  Settlement, dated December 21, 2005, as filed with the Federal Energy  Regulatory Commission for approval to implement an additional component of  the Facilities Surcharge to permit recovery by Enbridge Energy, Limited  Partnership of the costs for the Southern Access Mainline Expansion and  approval of the Offer of Settlement dated March 16, 2006. |
| 31.1* |   | Certification of  Principal Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley  Act of 2002.                                                                                                                                                                                                                                                                |
| 31.2* |   | Certification of  Principal Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley  Act of 2002.                                                                                                                                                                                                                                                                |
| 32.1* |   | Certification of  Principal Executive Officer Pursuant to Section 906 of the Sarbanes-Oxley  Act of 2002.                                                                                                                                                                                                                                                                |
| 32.2* |   | Certification of  Principal Financial Officer Pursuant to Section 906 of the Sarbanes-Oxley  Act of 2002.                                                                                                                                                                                                                                                                |

 

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